Edgar Filing: PIONEER NATURAL RESOURCES CO

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-13245

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

Delaware

75-2702753

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


5205 N. O’Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

(972) 444-9001

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this Chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Number of shares of Common Stock outstanding as of August 6, 2009 115,064,128

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS


		Page

Cautionary Statement Concerning Forward-Looking Statements		3

Definitions of Certain Terms and Conventions Used Herein		4

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	5

	Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	7

	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2009	8

	Consolidated Statements of Cash Flows for the three and six months ended June 30, 2009 and 2008	9

	Consolidated Statements of Comprehensive Loss for the three and six months ended June 30, 2009 and 2008	10

	Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61

Item 4.	Controls and Procedures	64

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	65

Item 1A.	Risk Factors	65

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66

Item 4.	Submission of Matters to a Vote of Security Holders	66

Item 6.	Exhibits	68

Signatures		69

Exhibit Index		70

PIONEER NATURAL RESOURCES COMPANY

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (the “Report”) contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company (“Pioneer” or the “Company”) are intended to identify forward-looking statements. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control.

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, access to and availability of drilling equipment and transportation, processing and refining facilities, Pioneer’s ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, and acts of war or terrorism. These and other risks are described in the Company’s Annual Report on Form 10-K, this and other Quarterly Reports on Form 10-Q and other filings with the Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse impact on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk” and “Part II, Item 1A. Risk Factors” in this Report and “Item 1. Business — Competition, Markets and Regulations”, “Item 1A. Risk Factors” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. The Company undertakes no duty to publicly update these statements except as required by law.

PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following terms and conventions have specific meanings:

•

“Bbl” means a standard barrel containing 42 United States gallons.

•

“Bcf” means one billion cubic feet.

•

“BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

•

“BOEPD” means BOE per day.

•

“Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

•

“CBM” means coal bed methane.

•

“DD&A” means depletion, depreciation and amortization.

•

“field fuel” means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

•

“GAAP” means accounting principles that are generally accepted in the United States of America.

•

“IPO” means initial public offering.

•

“LIBOR” means London Interbank Offered Rate, which is a market rate of interest.

•

“LNG” means liquefied natural gas.

•

“MBbl” means one thousand Bbls.

•

“MBOE” means one thousand BOEs.

•

“Mcf” means one thousand cubic feet and is a measure of natural gas volume.

•

“MMBbl” means one million Bbls.

•

“MMBOE” means one million BOEs.

•

“MMBtu” means one million Btus.

•

“MMcf” means one million cubic feet.

•

“MMcfpd” means one million cubic feet per day.

•

“Mont Belvieu–posted-price” means the daily average natural gas liquids components as priced in Oil Price Information Service (“OPIS”) in the table “U.S. and Canada LP – Gas Weekly Averages” at Mont Belvieu, Texas.

•

“NGL” means natural gas liquid.

•

“NYMEX” means the New York Mercantile Exchange.

•

“NYSE” means the New York Stock Exchange.

•

“Pioneer” or the “Company” means Pioneer Natural Resources Company and its subsidiaries.

•

“Pioneer Southwest” means Pioneer Southwest Energy Partners L.P. and its subsidiaries.

•

“proved reserves” mean the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

•

“SEC” means the United States Securities and Exchange Commission.

•

“Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs in effect at the specified date and a ten percent discount rate.

•

“U.S.” means United States.

•

“VPP” means volumetric production payment.

•

With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

•

Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	June 30, 2009			December 31, 2008 (a)
ASSETS
Current assets:
Cash and cash equivalents	$	64,323		$	48,337
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,472 and $22,464 as of June 30, 2009 and December 31, 2008, respectively		152,231			206,794
Due from affiliates		700			759
Income taxes receivable		28,777			60,573
Inventories		119,077			76,901
Prepaid expenses		19,870			12,464
Deferred income taxes		9,239			6,510
Discontinued operations held for sale		16,874			—
Other current assets:
Derivatives		63,830			59,622
Other, net of allowance for doubtful accounts of $5,566 and $5,491 as of June 30, 2009 and December 31, 2008, respectively		6,929			14,951

Total current assets		481,850			486,911

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		10,105,381			10,167,220
Unproved properties		197,986			204,183
Accumulated depletion, depreciation and amortization		(2,671,508	)		(2,511,401	)

Total property, plant and equipment		7,631,859			7,860,002

Deferred income taxes		1,134			553
Goodwill		310,551			310,563
Other property and equipment, net		158,775			161,266
Other assets:
Derivatives		40,337			72,594
Other, net of allowance for doubtful accounts of $5,167 and $4,410 as of June 30, 2009 and December 31, 2008, respectively		248,336			269,896

	$	8,872,842		$	9,161,785

(a)	Retrospectively adjusted as described in Note B.

The financial information included as of June 30, 2009 has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

(Unaudited)


	June 30, 2009			December 31, 2008 (a)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	192,542		$	322,688
Due to affiliates		13,262			34,284
Interest payable		43,348			43,247
Income taxes payable		17,713			3,618
Deferred income taxes		370			—
Discontinued operations held for sale		16,706			—
Other current liabilities:
Derivatives		108,360			49,561
Deferred revenue		119,281			147,905
Other		68,177			93,694

Total current liabilities		579,759			694,997


Long-term debt		2,978,819			2,899,241
Derivatives		47,645			20,584
Deferred income taxes		1,424,769			1,501,459
Deferred revenue		132,166			177,236
Other liabilities		168,598			187,409
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 125,135,994 and 124,566,963 shares issued at June 30, 2009 and December 31, 2008, respectively		1,251			1,246
Additional paid-in capital		2,924,939			2,909,735
Treasury stock, at cost: 11,113,561 and 10,020,502 shares at June 30, 2009 and December 31, 2008, respectively		(426,598	)		(411,659	)
Retained earnings		875,226			988,786
Accumulated other comprehensive income - deferred hedge gains, net of tax		76,637			88,788

Total stockholders’ equity attributable to common stockholders		3,451,455			3,576,896
Noncontrolling interest in consolidating subsidiaries		89,631			103,963

Total stockholders’ equity		3,541,086			3,680,859
Commitments and contingencies

	$	8,872,842		$	9,161,785

(a)	Retrospectively adjusted as described in Note B.

The financial information included as of June 30, 2009 has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008 (a)			2009			2008 (a)
Revenues and other income:
Oil and gas	$	370,692		$	635,123		$	738,543		$	1,177,166
Derivative gains, net		—			881			—			1,908
Interest and other		88,598			6,887			99,258			31,911
Gain (loss) on disposition of assets, net		53			3,901			(62	)		4,578

		459,343			646,792			837,739			1,215,563

Costs and expenses:
Oil and gas production		84,793			97,327			195,223			190,140
Production and ad valorem taxes		23,715			45,658			51,414			83,546
Depletion, depreciation and amortization		165,943			112,251			354,087			216,888
Impairment of oil and gas properties		—			—			21,091			—
Exploration and abandonments		21,618			26,108			52,788			63,293
General and administrative		33,275			35,596			67,929			72,117
Accretion of discount on asset retirement obligations		2,753			1,961			5,505			3,904
Interest		43,475			41,670			84,613			81,948
Hurricane activity, net		16,075			1,401			16,450			1,859
Derivative losses, net		170,224			—			70,361			—
Other		36,715			8,275			68,104			20,190

		598,586			370,247			987,565			733,885

Income (loss) from continuing operations before income taxes		(139,243	)		276,545			(149,826	)		481,678
Income tax benefit (provision)		44,398			(120,975	)		45,139			(204,451	)

Income (loss) from continuing operations		(94,845	)		155,570			(104,687	)		277,227
Income from discontinued operations, net of tax		2,731			7,351			1,761			14,391

Net income (loss)		(92,114	)		162,921			(102,926	)		291,618
Net (income) loss attributable to the noncontrolling interest		522			(6,227	)		(3,271	)		(6,965	)

Net income (loss) attributable to common stockholders	$	(91,592	)	$	156,694		$	(106,197	)	$	284,653

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.82	)	$	1.24		$	(0.95	)	$	2.26
Income from discontinued operations, net of tax, attributable to common stockholders		0.02			0.06			0.02			0.12

Net income (loss) attributable to common stockholders	$	(0.80	)	$	1.30		$	(0.93	)	$	2.38

Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.82	)	$	1.23		$	(0.95	)	$	2.25
Income from discontinued operations, net of tax, attributable to common stockholders		0.02			0.06			0.02			0.12

Net income (loss) attributable to common stockholders	$	(0.80	)	$	1.29		$	(0.93	)	$	2.37

Weighted average shares outstanding:
Basic		113,979			118,363			114,116			118,149

Diluted		113,979			119,370			114,116			118,816

Dividends declared per share	$	—		$	—		$	0.04		$	0.14

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	(94,323	)	$	149,343		$	(107,958	)	$	270,262
Discontinued operations, net of tax		2,731			7,351			1,761			14,391

Net income (loss)	$	(91,592	)	$	156,694		$	(106,197	)	$	284,653

(a)	Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands, except dividends per share)

(Unaudited)


	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interest			Total Stockholders’ Equity
Balance as of December 31, 2008 (a)	114,546		$	1,246	$	2,909,735		$	(411,659	)	$	988,786		$	88,788		$	103,963		$	3,680,859
Dividends declared ($0.04 per share)	—			—		—			—			(4,696	)		—			—			(4,696	)
Exercise of long-term incentive plan stock options	132			—		—			5,202			(2,667	)		—			—			2,535
Purchase of treasury stock	(1,225	)		—		—			(20,141	)		—			—			(258	)		(20,399	)
Tax benefits related to stock-based compensation	—			—		(3,918	)		—			—			—			—			(3,918	)
Compensation costs:
Vested compensation awards, net	569			5		(5	)		—			—			—			—			—
Compensation costs included in net income	—			—		19,127			—			—			—			96			19,223
Cash contributions of noncontrolling interest partners	—			—		—			—			—			—			150			150
Cash distributions to noncontrolling interest partners																		(10,050	)		(10,050	)
Net income (loss)	—			—		—			—			(106,197	)		—			3,271			(102,926	)
Other comprehensive loss:
Deferred hedging activity, net of tax:
Hedge fair value changes, net	—			—		—			—			—			10,477			3,692			14,169
Net hedge gains included in continuing operations	—			—		—			—			—			(22,628	)		(11,233	)		(33,861	)

Balance as of June 30, 2009	114,022		$	1,251	$	2,924,939		$	(426,598	)	$	875,226		$	76,637		$	89,631		$	3,541,086

(a)	Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008 (a)			2009			2008 (a)
Cash flows from operating activities:
Net income (loss)	$	(92,114	)	$	162,921		$	(102,926	)	$	291,618
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		165,943			112,251			354,087			216,888
Impairment of oil and gas properties		—			—			21,091			—
Exploration expenses, including dry holes		9,705			1,034			27,954			4,582
Hurricane activity, net		15,000			—			15,000			—
Deferred income taxes		(41,761	)		108,937			(52,793	)		171,310
(Gain) loss on disposition of assets, net		(53	)		(3,901	)		62			(4,578	)
Accretion of discount on asset retirement obligations		2,753			1,961			5,505			3,904
Discontinued operations		312			6,181			5,208			14,464
Interest expense		6,921			7,797			13,529			14,094
Derivative related activity		159,520			7,851			48,235			15,516
Amortization of stock-based compensation		9,926			8,268			19,223			17,248
Amortization of deferred revenue		(36,975	)		(39,457	)		(73,695	)		(78,936	)
Other noncash items		14,146			8,427			24,840			3,788
Change in operating assets and liabilities
Accounts receivable, net		11,720			(84,474	)		53,941			(98,535	)
Income taxes receivable		(13,140	)		(9,326	)		31,796			(9,402	)
Inventories		(23,219	)		(14,471	)		(57,689	)		(40,643	)
Prepaid expenses		(16,147	)		166			(14,187	)		1,103
Other current assets		40,863			5,191			66,920			7,186
Accounts payable		4,062			32,744			(107,388	)		(1,169	)
Interest payable		15,677			16,489			101			3,154
Income taxes payable		5,554			18,922			14,095			28,112
Other current liabilities		(14,786	)		(14,461	)		(44,581	)		(48,972	)

Net cash provided by operating activities		223,907			333,050			248,328			510,732

Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		3,542			13,640			3,742			145,773
Additions to oil and gas properties		(77,623	)		(319,341	)		(242,150	)		(616,608	)
Additions to other assets and other property and equipment, net		(14,663	)		(8,240	)		(21,399	)		(20,646	)

Net cash used in investing activities		(88,744	)		(313,941	)		(259,807	)		(491,481	)

Cash flows from financing activities:
Borrowings under long-term debt		—			23,998			172,000			615,998
Principal payments on long-term debt		(102,000	)		(186,998	)		(103,000	)		(732,775	)
Distributions to noncontrolling interest partners		(5,060	)					(9,900	)		—
Proceeds from issuance of partnership common units, net of issuance costs		—			165,978			—			165,978
Borrowings (payments) of other liabilities		(364	)		19,145			(699	)		13,255
Exercise of long-term incentive plan stock options		1,581			4,905			2,535			5,782
Purchase of treasury stock		(280	)		(562	)		(20,399	)		(27,512	)
Excess tax (costs) benefits from share-based payment arrangements		(39	)		(1,741	)		(3,918	)		404
Payment of financing fees		(4,475	)		(1,031	)		(4,475	)		(12,377	)
Dividends paid		(4,679	)		(16,841	)		(4,679	)		(16,893	)

Net cash provided by (used in) financing activities		(115,316	)		6,853			27,465			11,860

Net increase in cash and cash equivalents		19,847			25,962			15,986			31,111
Cash and cash equivalents, beginning of period		44,476			17,320			48,337			12,171

Cash and cash equivalents, end of period	$	64,323		$	43,282		$	64,323		$	43,282

(a)	Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008 (a)			2009			2008 (a)

Net income (loss)	$	(92,114	)	$	162,921		$	(102,926	)	$	291,618

Other comprehensive loss:
Hedge activity, net of tax:
Hedge fair value changes, net		—			(331,325	)		14,169			(471,592	)
Net hedge (gains) losses included in continuing operations		(3,032	)		103,354			(33,861	)		153,785

Other comprehensive loss		(3,032	)		(227,971	)		(19,692	)		(317,807	)

Comprehensive loss		(95,146	)		(65,050	)		(122,618	)		(26,189	)

Comprehensive loss attributable to noncontrolling interest		6,057			12,804			4,270			12,066

Comprehensive loss attributable to common stockholders	$	(89,089	)	$	(52,246	)	$	(118,348	)	$	(14,123	)

(a)	Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE A.

Organization and Nature of Operations

Pioneer is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations in the United States, South Africa and Tunisia.

NOTE B.

Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2009 and for the three and six months ended June 30, 2009 and 2008 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. These consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

Discontinued operations. During the three months ended June 30, 2009, the Company committed to a plan to sell its shelf properties in the Gulf of Mexico and sold its Mississippi assets. The Company completed the sale of its shelf properties in the Gulf of Mexico on August 6, 2009. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), the Company has classified the assets and liabilities of its shelf properties in the Gulf of Mexico as discontinued operations held for sale in the accompanying consolidated balance sheet as of June 30, 2009, and reflected the results of operations of both the planned and completed divestitures as discontinued operations, rather than as a component of continuing operations. In April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries. During the three and six months ended June 30, 2008, the Company continued to realize certain revenues and costs and expense increments associated with these divestitures. See Note R for additional information regarding discontinued operations.

Allowances for doubtful accounts. As of June 30, 2009 and December 31, 2008, the Company’s allowances for doubtful accounts totaled $12.2 million and $32.4 million, respectively. In accordance with SFAS No. 5, “Accounting for Contingencies,” the Company establishes allowances for bad debts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company’s consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.


	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
	(in thousands)

Beginning allowance for doubtful accounts balance	$	31,600		$	32,365
Amount recorded in other expense for bad debt expense (recoveries)		(58	)		(744	)
Write-offs of uncollectible accounts		(19,337	)		(19,416	)


Ending allowance for doubtful accounts balance	$	12,205		$	12,205

Inventories. Inventories consisted of $219.0 million and $158.7 million of materials and supplies and $3.8 million and $8.7 million of commodities as of June 30, 2009 and December 31, 2008, respectively. The Company’s materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to charge to the joint accounts when the inventory is used in joint operations under joint operating agreements to which the Company is a party. Any valuation reserve allowances of materials and supplies inventory are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. As of June 30, 2009 and December 31, 2008, the Company’s materials and supplies inventory was net of $6.1 million and $4.7 million, respectively, of valuation reserve allowances. The Company estimated that approximately $103.7 million and $90.2 million of its June 30, 2009 and December 31, 2008 materials and supplies inventories, respectively, would not be utilized within one year based on current drilling plans. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodities inventories consist of oil and natural gas liquids (“NGLs”) held in storage. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to other expense in the consolidated statements of operations. As of December 31, 2008, the Company’s commodities inventories were net of $159 thousand of valuation allowances.

Derivatives and hedging. Prior to December 2008, the Company had elected to designate the majority of its commodity derivative instruments as cash flow hedges. During December 2008, the Company began entering into commodity derivative contracts that were not designated as hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). Changes in the fair values of non-hedge derivative instruments are recognized as gains or losses in the earnings of the period in which they occur. Effective February 1, 2009, the Company discontinued hedge accounting on all existing hedge contracts. The effective portions of the discontinued deferred hedges as of January 31, 2009 are included in accumulated other comprehensive income – deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the accompanying consolidated balance sheets, and are being reclassified to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. For the period from February 1, 2009 through June 30, 2009, the Company recognized, and in the future will recognize, all changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

In accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities by commodity, whichever the case may be. Net derivative asset values are determined, in part, by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company’s credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates are based on an independent market-quoted credit default swap rate curve for the Company’s or the counterparties’ debt plus the United States Treasury Bill yield curve as of June 30, 2009.

Goodwill. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2008, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment. However, as a result of commodity prices and the market capitalization of the Company declining significantly during the second half of 2008, which the Company considered an event that might indicate impairment to the carrying value of goodwill, the Company reassessed goodwill for impairment at December 31, 2008 and quarterly thereafter and determined that there was no impairment. See Note M for additional information regarding the Company’s impairment assessments.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 68.3 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties previously owned by the Company in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations, and cash flows of Pioneer Southwest are consolidated with those of the Company.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

In addition to Pioneer Southwest, the Company owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interest in the net assets of consolidated subsidiaries totaled $89.6 million and $104.0 million as of June 30, 2009 and December 31, 2008, respectively. The Company recorded a net loss attributable to the noncontrolling interests (principally related to Pioneer Southwest) for the three months ended June 30, 2009 of $522 thousand, net income of $3.3 million for the six months ended June 30, 2009, and net income of $6.2 million and $7.0 million for the three and six months ended June 30, 2008, respectively. See “New accounting pronouncements” and “Reclassifications and retrospective adjustments” for information regarding the Company’s adoption of SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB Statement No. 51” (“SFAS 160”).

Stock-based compensation. For stock-based compensation awards, compensation expense is being recognized in the Company’s financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the stock price on the date of grant for the fair value of restricted stock awards and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.

For the three and six month periods ended June 30, 2009, the Company recorded $9.9 million and $19.2 million of stock-based compensation costs for all plans, respectively, as compared to $8.3 million and $17.2 million for the same respective periods of 2008.

In accordance with GAAP, the Company’s issued shares, as reflected in the consolidated balance sheets at June 30, 2009 and December 31, 2008, do not include 1,021,413 and 1,078,267, respectively, of issued but unvested shares awarded under stock-based compensation plans which have voting rights.

The following table summarizes all stock-based awards, lapses and forfeitures that occurred during the six months ended June 30, 2009:


	Restricted Stock Shares	Restricted Stock Units	Performance Units	Stock Options

Awards	378,497	1,622,152	189,247	361,021
Lapsed restrictions	424,453	144,578	—	—
Exercises	—	—	—	131,911
Forfeitures	10,898	26,511	—	99,118

As of June 30, 2009, there was approximately $65.0 million of unrecognized compensation expense related to unvested share-based compensation plan awards, related to restricted stock, restricted stock units, performance unit awards and stock options. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

New accounting pronouncements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measures” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. During February 2008, the FASB issued FASB Staff Position No. 157-2, “FSP FAS 157-2” (“FSP FAS 157-2”). FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2009, the Company adopted the remaining provisions of SFAS 157, for which delayed adoption was provided under FSP FAS 157-2.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer’s shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the recognition of capitalized research and development costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. The provisions of SFAS 141(R) also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. SFAS 141(R) is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. The Company became subject to the provisions of SFAS 141(R) on January 1, 2009.

In December 2007, the FASB issued SFAS 160. SFAS 160 amends Accounting Research Bulletin (“ARB”) No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated earnings to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. The Company adopted the provisions of SFAS 160 on January 1, 2009.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities by requiring entities to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 was adopted by the Company on January 1, 2009. See Note G for disclosures about the Company’s derivative instruments and hedging activities.

In May 2008, the FASB issued FASB Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (“FSP APB 14-1”). FSP APB 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company adopted the provisions of FSP APB 14-1 on January 1, 2009. The adoption of FSP APB 14-1 increases the annual interest expense that the Company recognizes on its $480 million of 2.875% convertible senior notes due 2038 (“2.875% Convertible Senior Notes”) from an annual yield of 2.875 percent to 6.75 percent, the annual yield equivalent to a nonconvertible debt borrowing at the time of issuance. The adoption of FSP APB 14-1 also resulted in the reclassification of the estimated issuance date fair value of the 2.875% Convertible Senior Notes conversion privilege from long-term debt to shareholders’ equity in the accompanying consolidated balance sheets. See “Reclassifications and retrospective adjustments” and Note F for additional information regarding the Company’s adoption of FSP APB 14-1.

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income (loss) allocation in computing basic and diluted earnings per share under the two class method prescribed under SFAS 128, “Earnings per Share”. The Company adopted the provisions of FSP EITF 03-6-1 on January 1, 2009 and, in accordance with FSP EITF 03-6-1, applied its provisions retrospectively to prior-period earnings per share computations. See Note K for additional information regarding the Company’s basic and diluted earnings per share computations for the three and six months ended June 30, 2009 and 2008.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. During February 2009, the FASB announced a project to amend SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”) to conform to the Reserve Ruling. The Company is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1”), which amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments” and Accounting Principles Board Opinion No. 28, “Interim Financial Reporting”. FSP FAS 107-1 requires fair value disclosures by publicly traded companies of financial instruments for interim reporting purposes. FSP FAS 107-1 was adopted by the Company during the second quarter of 2009. See Note D for disclosures about the fair values of the Company’s financial instruments.

Reclassifications and retrospective adjustments. Certain reclassifications have been made to the 2008 amounts in order to conform to the 2009 presentation and for the retrospective application of the adoption of SFAS 160. The retrospective application of SFAS 160 resulted in the reclassification of $59.2 million from minority interest in consolidated subsidiaries and $44.8 million from AOCI – Hedging to Noncontrolling interest in consolidated subsidiaries at December 31, 2008. In addition, the adoption of FSP APB 14-1 and FSP EITF 03-6-1 required retrospective adjustments to the Company’s financial statements as of December 31, 2008 and the three and six months ended June 30, 2008. The retrospective adjustments related to the adoption of FSP APB 14-1 decreased the Company’s net income attributable to common stockholders by $2.1 million (approximately $.02 per diluted share) and $3.9 million (approximately $.03 per diluted share), respectively, for the three and six months ended June 30, 2008. The retrospective application of FSP APB 14-1 also increased additional paid-in capital by $49.5 million and decreased retained earnings by $10.0 million as of December 31, 2008. The retrospective application of the provisions of FSP EITF 03-6-1 to the reported per-share amounts of the three and six months ended June 30, 2008 reduced the Company’s diluted earnings of each period by approximately $.01 per share, exclusive of the effects from the adoption of FSP APB 14-1.

NOTE C.

Exploratory Well Costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are presented in proved properties in the consolidated balance sheets. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense.

The following table reflects the Company’s capitalized exploratory well activity during the three and six months ended June 30, 2009:


	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
	(in thousands)

Beginning capitalized exploratory well costs	$	123,839		$	124,014
Additions to exploratory well costs pending the determination of proved reserves		12,196			26,338
Reclassification due to determination of proved reserves		(17,811	)		(27,201	)
Exploratory well costs charged to exploration expense		(4,227	)		(9,154	)


Ending capitalized exploratory well costs	$	113,997		$	113,997

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

The following table provides an aging, as of June 30, 2009 and December 31, 2008, of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:


	June 30, 2009		December 31, 2008
	(in thousands, except project counts)

Capitalized exploratory well costs that have been suspended:
One year or less	$	20,471	$	54,423
More than one year		93,526		69,591


	$	113,997	$	124,014


Number of projects with exploratory well costs that have been suspended for a period greater than one year		6		4

The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of June 30, 2009:


	Total		2009			2008		2007		2006
	(in thousands)

United States:
Cosmopolitan Unit	$	60,495	$	1,834		$	6,344	$	51,488	$	829
Other		2,525		(282	)		2,807		—		—
Tunisia		30,506		1,261			20,866		4,434		3,945

Total	$	93,526	$	2,813		$	30,017	$	55,922	$	4,774

Cosmopolitan Unit. The Company owns a 100 percent working interest in, and is the operator of, the Cosmopolitan Unit in the Cook Inlet of Alaska. During 2007, the Company drilled the Hansen #1A L1 well, a lateral sidetrack from an existing wellbore, to appraise the resource potential of the unit. The initial unstimulated production test results were encouraging. As a result, the Company began permitting and facilities planning during 2008 to further evaluate the unit’s resource potential. During 2009, the Company plans to continue with permitting, progress engineering studies and develop plans for a second well to be drilled in 2010 to further delineate the extent of the unit’s resource potential.

Tunisia – Cherouq. The Company has $17.6 million and $5.0 million of suspended well costs recorded for the Hayaat #1 and Hilal #1 wells, respectively, in the Company’s Cherouq production concession area, which is operated by the Company. The Hayaat #1 well began drilling in April 2008 to test several targeted formations. Mechanical failures were encountered during the testing of the well that did not allow completion of the formation assessments. The Company is analyzing seismic and other data to determine the optimal plan forward for completing the well, which may utilize the existing wellbore or a new wellbore adjacent to the existing well. The Company expects to finalize its Hayaat #1 plans and complete its assessment activities during 2010 or 2011.

The Hilal #1 well was originally drilled as an exploration well during 2007. The well was unsuccessful; however, the well is being re-completed to a formation that will be used for water disposal in support of other Cherouq operations. The Company recorded a $1.5 million dry hole charge for the Hilal #1 during 2007, representing the portion of the well costs that will not be used in disposal operations. Installation of the surface equipment is underway and disposal operations are planned to start during the second half of 2009.

Tunisia – Borj El Khadra prospects. The Company has $7.9 million of suspended well costs attributable to the Nahkil #1 and Abir #1 wells in the Borj El Khadra exploration permit area, which is operated by a third-party. The Nahkil #1 well encountered oil-bearing sands and the Abir #1 well encountered gas-bearing sands. The Company does not record proved reserves associated with discoveries in exploration permit areas until a production concession is granted. Infrastructure planning is underway and further exploration of the permit area is planned to occur in 2009 or 2010.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE D.

Disclosures About Fair Value Measurements

The valuation framework of SFAS 157 is based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

•

Level 1 – quoted prices for identical assets or liabilities in active markets.

•

Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

•

Level 3 – unobservable inputs for the asset or liability.

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2009, for each of the fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using						Fair Value at June 30, 2009
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2009
	(in thousands)
Assets:
Trading securities	$	53	$	188	$	—	$	241
Commodity derivatives		—		96,939		7,228		104,167
Deferred compensation plan assets		23,445		—		—		23,445

Total assets	$	23,498	$	97,127	$	7,228	$	127,853


Liabilities:
Commodity derivatives	$	—	$	144,701	$	1,762	$	146,463
Interest rate derivatives		—		9,542		—		9,542

Total liabilities	$	—	$	154,243	$	1,762	$	156,005

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

The following tables present the changes in the fair values of the Company’s net commodity derivative assets classified as Level 3 in the fair value hierarchy:


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended June 30, 2009
	NGL Swap Contracts			Gas Three-Way Collars			Oil Three-Way Collars			Total
	(in thousands)

Beginning balance	$	16,470		$	(1,697	)	$	3,364		$	18,137
Total gains (losses) (a):
Net unrealized losses included in earnings		(8,666	)		—			—			(8,666	)
Net realized losses included in earnings		(780	)		—			—			(780	)
Settlements		(1,558	)								(1,558	)
Transfers into/out of Level 3		—			1,697			(3,364	)		(1,667	)

Ending balance	$	5,466		$	—		$	—		$	5,466

(a)

The hedge-effective portions of realized gains and losses on commodity derivatives in AOCI – Hedging are included in oil and gas revenues, while non-hedge derivatives or ineffective portions of realized and unrealized gains and losses are included in derivative losses, net in the accompanying consolidated statements of operations.


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Six Months Ended June 30, 2009
	NGL Swap Contracts			Gas Three-Way Collars			Oil Three-Way Collars			Total
	(in thousands)

Beginning balance	$	18,560		$	—		$	—		$	18,560
Total gains (losses):
Net unrealized gains (losses) included in earnings (a)		(6,565	)		(1,697	)		3,364			(4,898	)
Net derivative losses included in other comprehensive income		(1,855	)		—			—			(1,855	)
Net realized losses included in earnings (a)		(371	)		—			—			(371	)
Settlements		(4,303	)								(4,303	)
Transfers into/out of Level 3		—			1,697			(3,364	)		(1,667	)

Ending balance	$	5,466		$	—		$	—		$	5,466

(a)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of June 30, 2009 and December 31, 2008:


	June 30, 2009				December 31, 2008
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	104,167	$	104,167	$	132,216	$	132,216
Trading securities	$	241	$	241	$	356	$	356
Deferred compensation plan assets	$	23,445	$	23,445	$	18,276	$	18,276
Notes receivable due 2008 to 2011	$	10,447	$	10,447	$	11,258	$	11,258
Liabilities:
Commodity price derivatives	$	146,463	$	146,463	$	60,242	$	60,242
Interest rate derivatives	$	9,542	$	9,542	$	9,903	$	9,903
Credit facility	$	982,000	$	937,032	$	913,000	$	868,597
2.875% senior convertible notes due 2038	$	422,239	$	399,120	$	415,194	$	345,600
5.875 % senior notes due 2012	$	6,180	$	6,007	$	6,191	$	5,233
5.875 % senior notes due 2016	$	385,479	$	374,554	$	382,010	$	301,583
6.65 % senior notes due 2017	$	483,852	$	429,071	$	483,792	$	339,570
6.875 % senior notes due 2018	$	449,146	$	388,143	$	449,132	$	292,175
7.20 % senior notes due 2028	$	249,923	$	197,179	$	249,922	$	145,000

Trading securities and deferred compensation plan assets. The Company’s trading securities represent equity securities that are not actively traded on major exchanges and, to a lesser extent, trading securities that are actively traded on major exchanges. The Company’s deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges plus unallocated contributions as of the measurement date. As of June 30, 2009, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for trading securities that are not actively traded on major exchanges, which were provided by broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company’s interest rate derivative liabilities represent swap contracts for $400 million notional amount of debt, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. The net derivative liability values attributable to the Company’s interest rate derivative contracts as of June 30, 2009 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company’s commodity derivatives represent oil, NGL and gas swap and collar contracts. The Company’s oil and gas swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority while NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.

Oil derivatives. The Company’s oil derivatives are swap, collar and three-way collar contracts for notional Bbls of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) NYMEX West Texas Intermediate (“WTI”) oil prices. The asset and liability values attributable to the Company’s oil derivatives as of June 30, 2009 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on market-quoted volatility factors adjusted for estimated volatility skews and corroborated with average volatility factors provided by the Company’s counterparties.

NGL derivatives. The Company’s NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The asset and liability values attributable to the Company’s NGL derivatives as of June 30, 2009 are based on (i) the contracted notional volumes, (ii) independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the applicable credit-adjusted risk-free rate yield curve.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Gas derivatives. The Company’s gas derivatives are swap, collar and three-way collar contracts for notional MMBtus of gas contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) swap contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company’s gas derivative contracts as of June 30, 2009 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) averages of forward posted price quotes supplied by independent brokers who are active in buying and selling gas derivatives at the indexes other than HH (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on market-quoted volatility factors adjusted for estimated volatility skews and corroborated with average volatility factors provided by the Company’s counterparties.

The Company corroborated independent broker-supplied forward price quotes by comparing price quote samples to alternate observable market data.

Credit facility. The fair value of the Company’s credit facility is based on (i) contractual interest and fees, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s credit facility measurements represent Level 2 inputs in the hierarchy priority.

Senior notes. The Company’s senior notes represent debt securities that are actively traded on major exchanges.

NOTE E.

Income Taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). SFAS 109 requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors to assess the likelihood that the Company’s net operating loss carryforwards (“NOLs”) and other deferred tax attributes in the U.S. federal, state and foreign tax jurisdictions will be utilized prior to their expiration. As of June 30, 2009 and December 31, 2008, the Company’s valuation allowances (relating primarily to foreign tax jurisdictions) were $42.0 million and $37.5 million, respectively.

The Company also accounts for income taxes in accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2009, the Company had no unrecognized tax benefits (as defined in FIN 48). In connection with the adoption of FIN 48, the Company established a policy to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2003. As of June 30, 2009, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company’s future results of operations or financial position.

On June 30, 2009, pursuant to Tunisian law, the Company established an investment reserve equal to 20 percent of 2008 taxable profits on the Adam and Cherouq concessions and thereby reduced current taxes payable by $13.1 million with a corresponding offset to deferred income taxes in the Company’s accompanying consolidated balance sheets. The investment reserve will be used to fund future drilling activity or pipeline infrastructure projects in Tunisia.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Income tax (provisions) benefits. The Company’s income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Current:
U.S. federal	$	(777	)	$	14,328		$	294		$	8,908
U.S. state		(6,329	)		(686	)		(7,006	)		(1,597	)
Foreign		9,220			(25,680	)		(942	)		(40,451	)

		2,114			(12,038	)		(7,654	)		(33,140	)


Deferred:
U.S. federal		52,576			(84,481	)		56,104			(142,866	)
U.S. state		6,312			(5,422	)		6,033			(2,993	)
Foreign		(16,604	)		(19,034	)		(9,344	)		(25,452	)

		42,284			(108,937	)		52,793			(171,311	)


Income tax (provision) benefit	$	44,398		$	(120,975	)	$	45,139		$	(204,451	)

Discontinued operations. The Company’s income tax (provisions) benefits attributable to income from discontinued operations consisted of the following for three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Current:
Foreign	$	—		$	348		$	—		$	(171	)

		—			348			—			(171	)


Deferred:
U.S. federal		(1,472	)		(3,529	)		(949	)		(6,307	)
Foreign		—			47			—			870

		(1,472	)		(3,482	)		(949	)		(5,437	)


Income tax provision	$	(1,472	)	$	(3,134	)	$	(949	)	$	(5,608	)

NOTE F.

Long-term Debt

Lines of credit. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) that matures in April 2012, unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for initial aggregate loan commitments of $1.5 billion, which may be increased to a maximum aggregate amount of $2.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added. As of June 30, 2009, the Company had $982.0 million of outstanding borrowings under the Credit Facility and $46.0 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $472.0 million of unused borrowing capacity under the Credit Facility.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Effective April 29, 2009, the Company and the lenders under the Company’s Credit Facility amended the Credit Facility to provide the Company additional financial flexibility. The Credit Facility contains certain financial covenants, one of which required the Company to maintain a ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by Moody’s Investors Service, Inc. or Standard & Poors Ratings Group, Inc. The amendment changed that ratio to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio would revert to 1.75 to 1.0, and provides that the Company may include in the calculation of the present value of its oil and gas properties 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest. The covenant requiring the Company to maintain a ratio of total debt to total capitalization of no more than 0.60 to 1.0 was not changed.

The amendment also adjusted certain borrowing rates and commitment fees, and changed certain provisions relating to the consequences if a lender under the Credit Facility defaults in its obligations under the agreement. After taking into account the amendment, revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus .5 percent plus a defined alternate base rate spread margin (“ABR Margin”), which is currently one percent based on the Company’s debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”), which is currently two percent and is also determined by the Company’s debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus .125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company’s debt rating (currently 0.375 percent).

As of June 30, 2009, the Company was in compliance with all of its debt covenants.

Senior convertible notes. During January 2008, the Company issued $500 million principal amount of 2.875% Convertible Senior Notes, of which $480 million remains outstanding at June 30, 2009. Effective January 1, 2009, the Company adopted the provisions of FSP APB 14-1 and, in accordance therewith, the Company applied the provisions of FSP APB 14-1 on a retrospective basis. The initial adoption of FSP APB 14-1 decreased the carrying value of the 2.875% Convertible Senior Notes by $63.5 million, increased stockholders’ equity by $39.5 million and increased deferred tax liabilities by $24.0 million. For the three and six months ended June 30, 2009, the adoption of FSP APB 14-1 increased interest expense by $3.5 million and $7.0 million and increased the Company’s net loss by approximately $2.2 million ($.02 per diluted share) and $4.4 million ($.04 per diluted share).

NOTE G.

Derivative Financial Instruments

The Company uses financial derivative contracts to manage exposures to commodity price, interest rate and foreign currency fluctuations. The Company generally does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter physical delivery contracts to effectively provide commodity price protection. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, physical delivery contracts are not accounted for as derivative financial instruments in the financial statements.

All derivatives are recorded on the balance sheet at estimated fair value. Fair value is determined in accordance with SFAS 157 and is generally determined based on the credit-adjusted present value difference between the fixed contract price and the underlying market price at the determination date. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments and since that date has accounted for derivative instruments using the mark-to-market accounting method. Therefore, the Company will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Changes in the fair value of effective cash flow hedges prior to the Company’s discontinuance of hedge accounting on February 1, 2009 were recorded as a component of AOCI – Hedging, which has been or will be transferred to earnings when the hedged transaction is recognized in earnings. Any ineffective portion of changes in the fair value of hedge derivatives prior to February 1, 2009 was recorded in the earnings of the period of change. The ineffective portion was calculated as the difference between the change in fair value of the hedge derivative and the estimated change in cash flows from the item hedged.

Fair value derivatives. The Company monitors the debt capital markets and interest rate trends to identify opportunities to enter into and terminate interest rate derivative contracts, with the objective of reducing the Company’s costs of capital. As of June 30, 2009 and December 31, 2008, the Company was not a party to any fair value hedges.

Cash flow derivatives. The Company utilizes commodity swap and collar contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness and forward currency exchange agreements to reduce the effect of exchange rate volatility.

Oil prices. All material physical sales contracts governing the Company’s oil production have been tied directly or indirectly to the NYMEX prices. The following table sets forth the volumes in Bbls underlying the Company’s outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those contracts as of June 30, 2009:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production non-hedge derivatives (a):
2009 – Swap Contracts
Volume (Bbl)						5,500		10,500		8,000
Price per Bbl					$	74.72	$	62.99	$	67.02

2009 – Collar Contracts
Volume (Bbl)						2,000		2,000		2,000
Price per Bbl:
Ceiling					$	70.38	$	70.38	$	70.38
Floor					$	52.00	$	52.00	$	52.00

2009 – Collar Contracts with Short Puts
Volume (Bbl)						20,000		15,000		17,500
Price per Bbl:
Ceiling					$	62.38	$	69.72	$	65.52
Floor					$	51.40	$	51.47	$	51.43
Short Put					$	44.70	$	41.47	$	43.31

2010 – Swap Contracts
Volume (Bbl)		2,000		2,000		2,000		2,000		2,000
Price per Bbl	$	98.32	$	98.32	$	98.32	$	98.32	$	98.32

2010 – Collar Contracts with Short Puts
Volume (Bbl)		24,000		24,000		24,000		24,000		24,000
Price per Bbl:
Ceiling	$	83.46	$	83.46	$	83.46	$	83.46	$	83.46
Floor	$	66.08	$	66.08	$	66.08	$	66.08	$	66.08
Short	$	53.42	$	53.42	$	53.42	$	53.42	$	53.42
2011 – Collar Contracts
Volume (Bbl)		2,000		2,000		2,000		2,000		2,000
Price per Bbl:
Ceiling	$	170.00	$	170.00	$	170.00	$	170.00	$	170.00
Floor	$	115.00	$	115.00	$	115.00	$	115.00	$	115.00

2011 – Collar Contracts with Short Puts
Volume (Bbl)		19,000		19,000		19,000		19,000		19,000
Price per Bbl:
Ceiling	$	93.31	$	93.31	$	93.31	$	93.31	$	93.31
Floor	$	72.37	$	72.37	$	72.37	$	72.37	$	72.37
Short Put	$	58.32	$	58.32	$	58.32	$	58.32	$	58.32

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

(a)

Subsequent to June 30, 2009, the Company entered into additional swap contracts for (i) 750 Bbls per day of the Company’s fourth quarter 2009 production at an average price of $69.35 per Bbl, (ii) 500 Bbls per day of the Company’s 2010 production at an average price of $73.45 per Bbl, (iii) 750 Bbls per day of the Company’s 2011 production at an average price of $77.25 per Bbl and (iv) 3,000 Bbls per day of the Company’s 2012 and 2013 production at an average price of $79.32 and $81.02, respectively. Additionally, the Company entered into collar contracts with short puts for (i) 1,000 Bbls per day of the Company’s 2010 production with a ceiling price of $87.75 per Bbl, a floor price of $70.00 Bbl and a short put price of $55.00 per Bbl, (ii) 6,000 Bbls per day of the Company’s 2011 production with a ceiling price of $98.70 per Bbl, a floor price of $74.17 per Bbl and a short put price of $59.17 per Bbl and (iii) 1,000 Bbls of the Company’s 2012 and 2013 production with a ceiling price of $103.50 per Bbl and $111.50 per Bbl, respectively, a floor price of $80.00 per Bbl and $83.00 per Bbl, respectively, and a short put price of $65.00 per Bbl and $68.00 per Bbl, respectively.

The Company reports average oil prices per Bbl including the effects of oil quality adjustments, amortization of deferred volumetric production payment (“VPP”) revenue and the net effect of oil hedges. The following table sets forth (i) the Company’s oil prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to oil revenue from continuing operations and (iii) the net effect of settlements of oil price hedges on oil revenue from continuing operations for the three and six month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008

Average price reported per Bbl	$	70.89	$	88.27		$	61.83	$	82.55
Average price realized per Bbl	$	53.91	$	123.80		$	45.44	$	111.52
VPP increase to oil revenue (in millions)	$	24.7	$	26.0		$	49.2	$	52.0
Increase (decrease) to oil revenue from hedging activity (in millions)	$	23.9	$	(119.9	)	$	46.3	$	(199.3	)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Natural gas liquids prices. All material physical sales contracts governing the Company’s NGL production have been tied directly or indirectly to Mont Belvieu prices. The following table sets forth the volumes in Bbls under outstanding NGL derivative contracts and the weighted average Mont Belvieu-posted-prices per Bbl for those contracts as of June 30, 2009:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production non-hedge derivatives (a):
2009 – Swap Contracts
Volume (Bbl)						3,750		3,750		3,750
Price per Bbl					$	34.28	$	34.28	$	34.28

2010 – Swap Contracts
Volume (Bbl)		1,250		1,250		1,250		1,250		1,250
Price per Bbl	$	47.36	$	47.37	$	47.38	$	47.38	$	47.38

(a)	Subsequent to June 30, 2009, the Company entered into additional swap contracts for 750 Bbls per day of the Company’s 2011 and 2012 production at an average price of $34.65 per Bbl and $35.03 per Bbl, respectively.

The Company reports average NGL prices per Bbl including the effects of NGL quality adjustments and the net effect of NGL derivatives. The following table sets forth (i) the Company’s NGL prices from continuing operations, both reported (including hedge results) and realized (excluding hedge results) and (ii) the net effect of NGL price hedges on NGL revenue from continuing operations for the three- and six-month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Average price reported per Bbl	$	26.78	$	56.28		$	24.69	$	55.10
Average price realized per Bbl	$	25.42	$	57.10		$	23.45	$	55.71
Increase (decrease) to NGL revenue from hedging activity (in millions)	$	2.4	$	(1.5	)	$	4.7	$	(2.2	)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Gas prices. All material physical sales contracts governing the Company’s gas production have been tied directly or indirectly to regional index prices where the gas is produced. The Company uses derivative contracts to mitigate gas price volatility and reduce basis risk between NYMEX prices and actual index prices upon which the gas is sold. The following table sets forth the volumes in MMBtus under outstanding gas derivative contracts and the weighted average index prices per MMBtu for those contracts as of June 30, 2009:


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production non-hedge derivatives (a):
2009 – Swap Contracts
Volume (MMBtu)								135,000			135,000			135,000
Price per MMBtu							$	6.25		$	6.16		$	6.21

2009 – Collar Contracts
Volume (MMBtu)								20,000			20,000			20,000
Price per MMBtu:
Ceiling							$	5.90		$	5.90		$	5.90
Floor							$	4.00		$	4.00		$	4.00

2009 – Collar Contracts with Short Puts
Volume (MMBtu)								150,000			150,000			150,000
Price per MMBtu:
Ceiling							$	5.35		$	5.35		$	5.35
Floor							$	4.18		$	4.18		$	4.18
Short Put							$	3.18		$	3.18		$	3.18

2009 – Basis Swap Contracts
Volume (MMBtu)								285,000			285,000			285,000
Price per MMBtu							$	(0.96	)	$	(0.96	)	$	(0.96	)

2010 – Swap Contracts
Volume (MMBtu)		125,000			125,000			125,000			125,000			125,000
Price per MMBtu	$	6.60		$	6.60		$	6.60		$	6.60		$	6.60

2010 – Collar Contracts
Volume (MMBtu)		30,000			30,000			30,000			30,000			30,000
Price per MMBtu:
Ceiling	$	7.52		$	7.52		$	7.52		$	7.52		$	7.52
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00

2010 – Collar Contracts with Short Puts
Volume (MMBtu)		95,000			95,000			95,000			95,000			95,000
Price per MMBtu:
Ceiling	$	7.94		$	7.94		$	7.94		$	7.94		$	7.94
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short Put	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

2010 – Basis Swap Contracts
Volume (MMBtu)		205,000			205,000			205,000			205,000			205,000
Price per MMBtu	$	(0.80	)	$	(0.80	)	$	(0.80	)	$	(0.80	)	$	(0.80	)

2011 – Collar Contracts with Short Puts
Volume (MMBtu)		50,000			50,000			50,000			50,000			50,000
Price per MMBtu:
Ceiling	$	9.36		$	9.36		$	9.36		$	9.36		$	9.36
Floor	$	7.00		$	7.00		$	7.00		$	7.00		$	7.00
Short Put	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00

2011 – Basis Swap Contracts
Volume (MMBtu)		60,000			60,000			60,000			60,000			60,000
Price per MMBtu	$	(0.82	)	$	(0.82	)	$	(0.82	)	$	(0.82	)	$	(0.82	)

2012 – Basis Swap Contracts
Volume (MMBtu)		20,000			20,000			20,000			20,000			20,000
Price per MMBtu	$	(0.78	)	$	(0.78	)	$	(0.78	)	$	(0.78	)	$	(0.78	)

2013 – Basis Swap Contracts
Volume (MMBtu)		10,000			10,000			10,000			10,000			10,000
Price per MMBtu	$	(0.71	)	$	(0.71	)	$	(0.71	)	$	(0.71	)	$	(0.71	)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

(a)

Subsequent to June 30, 2009, the Company entered into additional swap contracts for (i) 815 MMBtu per day and 2,500 MMBtu per day of the Company’s third and fourth quarter production, respectively, at an average price of $4.48 per MMBtu, (ii) 27,295 MMBtu per day of the Company’s 2010 production at an average price of $5.59 per MMBtu and (iii) 2,500 MMBtu per day of the Company’s 2011, 2012 and 2013 production at an average price of $6.65 per MMBtu, $6.77 per MMBtu and $6.89 per MMBtu, respectively. Subsequent to June 30, 2009 the Company also entered into additional collar contracts with short puts for 50,000 MMBtu per day at a ceiling price of $8.55 per MMBtu, a floor price of $6.00 per MMBtu and a short put price of $4.50 per MMBtu. Subsequent to June 30, 2009, the Company also entered into additional basis swap contracts for (i) 10,000 MMBtu per day of the Company’s 2010 production at an average price differential of $0.26 per MMBtu and (ii) 40,000 MMBtu per day of the Company’s 2011 production at an average price differential of $0.54 per MMBtu.

The Company reports average gas prices per Mcf including the effects of Btu content, gas processing, shrinkage adjustments, amortization of deferred VPP revenue and the net effect of gas hedges. The following table sets forth (i) the Company’s gas prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to gas revenue from continuing operations and (iii) the net effect of settlements of gas price hedges on gas revenue from continuing operations for the three- and six-month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008

Average price reported per Mcf	$	3.43	$	8.70		$	3.90	$	8.21
Average price realized per Mcf	$	3.02	$	9.54		$	3.31	$	8.44
VPP increase to gas revenue (in millions)	$	12.3	$	13.5		$	24.5	$	26.9
Increase (decrease) to gas revenue from hedging activity (in millions)	$	2.3	$	(42.2	)	$	19.0	$	(42.7	)

Interest rate. During January 2008, the Company entered into interest rate swap contracts and designated the contracts as cash flow hedges of the forecasted interest rate risk associated with a portion of the Company’s Credit Facility indebtedness. The interest rate swap contracts are variable-for-fixed-rate swaps on $400 million notional amount of debt at a weighted average fixed annual rate of 2.87 percent, excluding any applicable margins. The interest rate swaps had an effective start date of February 2008, with $200 million terminating during February 2010 and $200 million during February 2011.

Hedge ineffectiveness. On February 1, 2009, the Company discontinued hedge accounting. As a result, the Company only recorded ineffectiveness during January 2009, which was nominal. During the three and six months ended June 30, 2008, the Company recorded net ineffectiveness income of $.9 million and $1.9 million, respectively. Hedge ineffectiveness represents the ineffective portions of changes in the fair values of the Company’s cash flow hedging instruments. The primary causes of hedge ineffectiveness were changes in forecasted hedged sales volumes and commodity price correlations.

Tabular disclosure of derivative fair value. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments, and since that date forward has accounted for derivative instruments

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

using the mark-to-market accounting method. All of the Company’s derivatives were made up of non-hedge derivatives as of June 30, 2009 and both hedge derivatives and non-hedge derivatives as of December 31, 2008. The following tables provide disclosure of the Company’s derivative instruments:


Fair Value of Derivative Instruments as of June 30, 2009
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments under SFAS 133
Commodity price derivatives	Derivatives - current	$	90,654	Derivatives - current	$	127,382
Interest rate derivatives	Derivatives - current		—	Derivatives - current		7,803
Commodity price derivatives	Derivatives - noncurrent		56,663	Derivatives - noncurrent		62,231
Interest rate derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		1,739

Total derivatives not designated as hedging instruments under SFAS 133			147,317			199,155

Total derivatives		$	147,317		$	199,155


Fair Value of Derivative Instruments as of December 31, 2008
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments under SFAS 133
Commodity price derivatives	Derivatives - current	$	3,606	Derivatives - current	$	20,233
Commodity price derivatives	Derivatives - noncurrent		3,972	Derivatives - noncurrent		—

Total derivatives not designated as hedging instruments under SFAS 133			7,578			20,233


Derivatives designated as hedging instruments under SFAS 133
Commodity price derivatives	Derivatives - current		57,367	Derivatives - current		24,195
Interest rate derivatives	Derivatives - current		—	Derivatives - current		6,484
Commodity price derivatives	Derivatives - noncurrent		68,622	Derivatives - noncurrent		17,165
Interest rate derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		3,419

Total derivatives designated as hedging instruments under SFAS 133			125,989			51,263

Total derivatives		$	133,567		$	71,496

(a)	Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

(b)	Represent derivative obligations under terminated hedge arrangements.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)


Derivatives in SFAS 133 Cash Flow Hedging Relationships		Amount of Gain/(Loss) Recognized in AOCI on Effective Portion
		Three Months Ended June 30,						Six Months Ended June 30,
		2009			2008			2009			2008
		(in thousands)

Interest rate derivatives		$	—		$	8,420		$	(433	)	$	5,101
Commodity price derivatives			—			(565,927	)		4,968			(789,799	)

Total		$	—		$	(557,507	)	$	4,535		$	(784,698	)


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
		2009			2008			2009			2008
		(in thousands)

Interest rate derivatives	Interest expense	$	(2,017	)	$	(332	)	$	(4,272	)	$	(305	)
Commodity price derivatives	Oil and gas revenue		28,490			(163,527	)		69,912			(244,214	)

Total		$	26,473		$	(163,859	)	$	65,640		$	(244,519	)


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Location of Gain/(Loss) Recognized in Earnings on Ineffective Portion	Amount of Gain/(Loss) Recognized in Earnings on Ineffective Portion
		Three Months Ended June 30,						Six Months Ended June 30,
		2009			2008			2009			2008
		(in thousands)

Commodity price derivatives	Derivative gains, net	$	—		$	881		$	—		$	1,908

Derivatives Not Designated as Hedging Instruments under SFAS 133	Location of Gain (Loss) Recognized in Earnings on Derivative	Amount of Gain (Loss) Recognized in Earnings on Derivative
		Three Months Ended June 30,						Six Months Ended June 30,
		2009			2008			2009			2008
		(in thousands)

Interest rate derivatives	Derivative losses, net	$	(2,319	)	$	—		$	(3,251	)	$	—
Commodity price derivatives	Derivative losses, net		(167,905	)		—			(67,110	)		—

Total		$	(170,224	)	$	—		$	(70,361	)	$	—

AOCI - Hedging. The fair value of the effective portion of the derivative contracts on January 31, 2009 is reflected in AOCI-Hedging and is being transferred to oil and gas revenue (for commodity derivatives) and interest expense (for interest rate derivatives) over the remaining term of the contracts. In accordance with the mark-to-market method of accounting, the Company will recognize all future changes in fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

As of June 30, 2009 and December 31, 2008, AOCI - Hedging represented net deferred gains of $76.6 million and $88.8 million, respectively. The AOCI - Hedging balance as of June 30, 2009 was comprised of $168.5 million of net deferred gains on the effective portions of discontinued commodity hedges, $9.3 million of net deferred losses on the effective portions of discontinued interest rate hedges, $45.4 million of associated net deferred tax provisions and a charge for $37.2 million of AOCI – Hedging attributable to noncontrolling interests. The $12.2 million decrease in net deferred hedge gains comprising AOCI—Hedging during the six months ended June 30, 2009 was primarily attributable to the transfer of net deferred hedge gains to earnings, partially offset by deferred fair value gains during January 2009 and a decrease in AOCI – Hedging attributable to noncontrolling interests. AOCI - Hedging attributable to noncontrolling interests represented $44.7 million of deferred gains, net of taxes as of December 31, 2008.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

During the twelve months ending June 30, 2010, the Company expects to reclassify approximately $95.0 million of AOCI – Hedging net deferred gains to oil and gas revenues and $5.2 million of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify approximately $12.1 million of net deferred income tax provisions associated with hedge derivatives during the year ending June 30, 2010 from AOCI - Hedging to income tax expense.

Discontinued commodity hedges. Effective on February 1, 2009, the Company discontinued all of its commodity and interest rates hedges and began accounting for the associated derivatives using the mark-to-market accounting method. Prior to February 1, 2009, the Company periodically discontinued commodity hedges by terminating the derivative positions when the underlying commodity prices reached a point that the Company believed would be the high or low price of the commodity prior to the scheduled settlement of the open commodity position. This allowed the Company to lock in gains or minimize losses associated with the open hedge positions. At the time of hedge discontinuation, the amounts recorded in AOCI—Hedging are maintained and amortized to earnings over the periods the production was scheduled to occur.

The following table sets forth, as of June 30, 2009, the scheduled amortization of net deferred gains and (losses) on discontinued commodity hedges that will be recognized as increases or (decreases) to the Company’s future oil and gas revenues:


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(in thousands)

2009 net deferred hedge gains							$	26,125		$	24,757		$	50,882
2010 net deferred hedge gains	$	21,700		$	22,029		$	22,353		$	22,417		$	88,499
2011 net deferred hedge gains	$	7,989		$	8,072		$	8,159		$	8,020		$	32,240
2012 net deferred hedge losses	$	(810	)	$	(791	)	$	(783	)	$	(772	)	$	(3,156	)

NOTE H.

Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Company’s asset retirement obligation transactions during the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Beginning asset retirement obligations	$	173,516		$	200,371		$	172,433		$	208,183
Liabilities assumed in acquisitions		—			21			—			21
New wells placed on production and changes in estimates (a)		15,327			630			15,366			(7,791	)
Liabilities reclassified to discontinued operations held for sale		(14,353	)		—			(14,353	)		—
Disposition of wells		(246	)		—			(246	)		—
Liabilities settled		(23,046	)		(17,271	)		(24,976	)		(18,804	)
Accretion of discount on continuing operations		2,753			1,961			5,505			3,904
Accretion of discount on discontinued operations		220			199			442			398


Ending asset retirement obligations	$	154,171		$	185,911		$	154,171		$	185,911

(a)	During the six months ended June 30, 2008, the Company recorded a $9.0 million decrease in the abandonment estimates and associated insurance recovery estimates for the East Cameron facility that was destroyed by Hurricane Rita in 2005.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2009 and December 31, 2008, the current portions of the Company’s asset retirement obligations were $22.7 million and $29.9 million, respectively.

NOTE I.

Postretirement Benefit Obligations

As of June 30, 2009 and December 31, 2008, the Company had $9.4 million and $9.6 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the consolidated balance sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of June 30, 2009 or December 31, 2008. Other than participants in the Company’s retirement plan, the participants of these plans are not current employees of the Company.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Beginning accumulated postretirement benefit obligations	$	9,504		$	10,401		$	9,612		$	10,494
Net benefit payments		(362	)		(265	)		(691	)		(563	)
Service costs		57			47			114			95
Accretion of interest		165			158			329			315


Ending accumulated postretirement benefit obligations	$	9,364		$	10,341		$	9,364		$	10,341

NOTE J.

Commitments and Contingencies

Legal actions. The Company is party to the legal actions that are described below. The Company is also a party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.

MOSH Holding. On April 11, 2005, the Company and its principal United States subsidiary, Pioneer Natural Resources USA, Inc., were named as defendants in MOSH Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (the “Trust”), which is before the Judicial District Court of Harris County, Texas (334th Judicial District) (the “Court”).

On April 27, 2009, the Company and all parties in the lawsuit reached an agreement to settle the lawsuit. Under the terms of the settlement agreement, the Company will pay to the Trust the sum of $13 million in exchange for a full and final release of all claims made or that could have been made in the lawsuit. The Company will also contribute to the Trust proceeds obtained from the Company’s sale of its complete interest, including its working interest, in the Brazos Block A-39 tract, which will be sold in conjunction with the Trust’s sale of its assets.

The settlement agreement is subject to customary conditions, including a condition that the settlement is not final until it is approved by the Court and the Court issues a final, non-appealable judgment disposing of all claims. On August 6, 2009, the Court issued an Interlocutory Judgment approving the settlement agreement. The Interlocutory Judgment, together with the settlement agreement and Findings of Fact and Conclusions of Law, disposes of all claims and claimants except five individuals who intervened in this lawsuit. Pioneer intends to file a motion seeking dismissal of the intervenors’ claims. Assuming Pioneer’s motion is granted, the intervenors’ claims will be dismissed, and a final judgment will be entered. Once such final judgment becomes non-appealable (or any timely appeals are resolved), then the settlement agreement will become final. Assuming that the intervenors’ claims are dismissed and no appeals are filed, it is expected that the settlement agreement will become final in the third or fourth quarter of 2009.

Colorado Notice of Violation. On May 13, 2008, the Company was served with a Notice of Violation/Cease and Desist Order by the State of Colorado Department of Public Health and Environmental Water Quality Control Division. The Notice alleges violations of stormwater discharge permits in the Company’s Raton Basin and Lay Creek

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

operations, specifically deficiencies in the Company’s stormwater management plans, failure to implement and maintain best management practices to protect stormwater runoff and failure to conduct inspections of the stormwater management system. The Company has filed an answer to the Notice asserting defenses to the allegations. The Company does not believe that the outcome of this proceeding will materially impact the Company’s liquidity, financial position or future results of operations.

SemGroup accounts receivable. The Company is a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries (collectively, “SemGroup”), which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008 in the U.S. Bankruptcy Court for the District of Delaware. In total, the Company had delinquent receivables from SemGroup of $29.6 million, representing claims for condensate sold pre-petition to SemGroup.

The Company determined that it was probable that the collection of the pre-petition claims would not occur for a protracted period of time and that some of its claims may have been uncollectible. Consequently, the Company recorded a bad debt expense of approximately $19.6 million during the third quarter 2008, which reduced the carrying value of the claims to approximately $10.0 million.

In April 2009, the Company sold all of its pre-petition claims against SemGroup to a third party for approximately $10.1 million, pursuant to a purchase agreement that contains customary representations, warranties and other provisions. If a portion of the claims become impaired due to circumstances arising from a breach of such representations and warranties, then the Company may be required to repurchase such impaired portion of the claims.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations. The Company does not believe that these obligations, which primarily pertain to matters of litigation, environmental contingencies, royalty obligations and income taxes, are probable of having a material impact on its liquidity, financial position or future results of operations.

The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale in 2007 of its Canadian assets.

NOTE K.

Earnings Per Share From Continuing Operations

Basic earnings per share from continuing operations is computed by dividing earnings from continuing operations attributable to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted earnings per share from continuing operations reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income from continuing operations were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods that the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to loss per share and conversion into common stock is assumed not to occur.

The Company’s earnings from continuing operations attributable to common stockholders is computed as income (loss) from continuing operations less participating share-based earnings. The following table is a reconciliation of the Company’s income (loss) from continuing operations to income (loss) from continuing operations attributable to common stockholders for the three- and six-month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Income (loss) from continuing operations	$	(94,845	)	$	155,570		$	(104,687	)	$	277,227

Participating share-based earnings		(122	)		(2,247	)		(98	)		(3,498	)

Income (loss) from continuing operations attributable to common stockholders	$	(94,967	)	$	153,323		$	(104,785	)	$	273,729

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

(a)

In accordance with FSP EITF 03-6-1, unvested restricted stock share awards and restricted stock unit awards represent participating securities because they participate in nonforfeitable dividends with the Company’s common stock. Participating share-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and restricted stock unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three- and six-month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
	(in thousands)

Weighted average common shares outstanding (a):
Basic	113,979	118,363	114,116	118,149
Dilutive common stock options (b)	—	332	—	329
Contingently issuable - performance shares (b)	—	83	—	42
Convertible notes dilution (c)	—	592	—	296


Diluted	113,979	119,370	114,116	118,816

(a)

In 2007, the Company’s board of directors (“Board”) approved a $750 million share repurchase program of which $355.8 million remained available for purchase as of June 30, 2009. During the first half of 2009 and 2008, the Company purchased $16.3 million and $12.8 million of common stock pursuant to the program, respectively.

(b)

Diluted earnings per share were calculated using the two-class method for the three- and six-month periods ended June 30, 2009 and June 30, 2008. The following common stock equivalents were excluded from the diluted loss per share calculations for the three and six month periods ended June 30, 2009 because they would have been anti-dilutive to the calculations: 770,531 and 554,816 unvested restricted shares or restricted stock units, respectively; 124,057 and 142,358 outstanding options to purchase the Company’s common stock, respectively; and 174,438 and 87,219 performance units, respectively.

(c)

During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes. Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the 2.875% Convertible Senior Notes had qualified for and been converted during the three- and six-month periods ended June 30, 2008. The 2.875% Convertible Senior Notes were not dilutive to the per share calculations of 2009.

NOTE L.

Geographic Operating Segment Information

The Company’s only operations are oil and gas exploration and producing activities; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable operations in the United States, South Africa and Tunisia.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

The following tables provide the Company’s geographic operating segment data for the three and six months ended June 30, 2009 and 2008. Geographic operating segment income tax (provisions) benefits have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis and operations in Equatorial Guinea and Nigeria, where the Company concluded exploration activities during 2007.


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2009
Revenues and other income:
Oil and gas	$	314,031		$	18,160		$	38,501		$	—		$	370,692
Interest and other		—			—			—			88,598			88,598
Gain on disposition of assets, net		7			—			—			46			53

		314,038			18,160			38,501			88,644			459,343

Costs and expenses:
Oil and gas production		75,389			445			8,959			—			84,793
Production and ad valorem taxes		23,715			—			—			—			23,715
Depletion, depreciation and amortization		132,482			20,446			5,750			7,265			165,943
Exploration and abandonments		17,978			195			3,244			201			21,618
General and administrative		—			—			—			33,275			33,275
Accretion of discount on asset retirement obligations		—			—			—			2,753			2,753
Interest		—			—			—			43,475			43,475
Hurricane activity, net		16,075			—			—			—			16,075
Derivative losses, net		—			—			—			170,224			170,224
Other		18,864			—			3,768			14,083			36,715

		284,503			21,086			21,721			271,276			598,586

Income (loss) from continuing operations before income taxes		29,535			(2,926	)		16,780			(182,632	)		(139,243	)
Income tax benefit (provision)		(10,928	)		849			(9,638	)		64,115			44,398

Income (loss) from continuing operations	$	18,607		$	(2,077	)	$	7,142		$	(118,517	)	$	(94,845	)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2008
Revenues and other income:
Oil and gas	$	521,380		$	37,985		$	75,758		$	—		$	635,123
Derivative gains, net		—			—			—			881			881
Interest and other		—			—			—			6,887			6,887
Gain on disposition of assets, net		515			—			—			3,386			3,901

		521,895			37,985			75,758			11,154			646,792

Costs and expenses:
Oil and gas production		82,936			8,369			6,022			—			97,327
Production and ad valorem taxes		45,658			—			—			—			45,658
Depletion, depreciation and amortization		96,710			4,651			3,656			7,234			112,251
Exploration and abandonments		20,302			3			2,887			2,916			26,108
General and administrative		—			—			—			35,596			35,596
Accretion of discount on asset retirement obligations		—			—			—			1,961			1,961
Interest		—			—			—			41,670			41,670
Hurricane activity, net		1,401			—			—			—			1,401
Other		6,975			—			—			1,300			8,275

		253,982			13,023			12,565			90,677			370,247

Income (loss) from continuing operations before income taxes		267,913			24,962			63,193			(79,523	)		276,545
Income tax benefit (provision)		(99,128	)		(7,239	)		(37,092	)		22,484			(120,975	)

Income (loss) from continuing operations	$	168,785		$	17,723		$	26,101		$	(57,039	)	$	155,570

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2009
Revenues and other income:
Oil and gas	$	641,815		$	29,965		$	66,763		$	—		$	738,543
Interest and other		—			—			—			99,258			99,258
Gain (loss) on disposition of assets, net		7			—			—			(69	)		(62	)

		641,822			29,965			66,763			99,189			837,739

Costs and expenses:
Oil and gas production		173,498			3,941			17,784			—			195,223
Production and ad valorem taxes		51,414			—			—			—			51,414
Depletion, depreciation and amortization		292,451			37,000			10,066			14,570			354,087
Impairment of oil and gas properties		21,091			—			—			—			21,091
Exploration and abandonments		41,369			289			10,549			581			52,788
General and administrative		—			—			—			67,929			67,929
Accretion of discount on asset retirement obligations		—			—			—			5,505			5,505
Interest		—			—			—			84,613			84,613
Hurricane activity, net		16,450			—			—			—			16,450
Derivative losses, net		—			—			—			70,361			70,361
Other		39,150			—			3,768			25,186			68,104

		635,423			41,230			42,167			268,745			987,565

Income (loss) from continuing operations before income taxes		6,399			(11,265	)		24,596			(169,556	)		(149,826	)
Income tax benefit (provision)		(2,368	)		3,267			(14,684	)		58,924			45,139

Income (loss) from continuing operations	$	4,031		$	(7,998	)	$	9,912		$	(110,632	)	$	(104,687	)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2008
Revenues and other income:
Oil and gas	$	996,984		$	67,565		$	112,617		$	—		$	1,177,166
Derivative gains, net											1,908			1,908
Interest and other		—			—			—			31,911			31,911
Gain on disposition of assets, net		513			—			—			4,065			4,578

		997,497			67,565			112,617			37,884			1,215,563

Costs and expenses:
Oil and gas production		162,530			18,349			9,261			—			190,140
Production and ad valorem taxes		83,546			—			—			—			83,546
Depletion, depreciation and amortization		187,924			9,043			5,377			14,544			216,888
Exploration and abandonments		44,634			52			13,001			5,606			63,293
General and administrative		—			—			—			72,117			72,117
Accretion of discount on asset retirement obligations		—			—			—			3,904			3,904
Interest		—			—			—			81,948			81,948
Hurricane activity, net		1,859			—			—			—			1,859
Other		14,836			—			—			5,354			20,190

		495,329			27,444			27,639			183,473			733,885

Income (loss) from continuing operations before income taxes		502,168			40,121			84,978			(145,589	)		481,678
Income tax benefit (provision)		(185,802	)		(11,635	)		(51,249	)		44,235			(204,451	)

Income (loss) from continuing operations	$	316,366		$	28,486		$	33,729		$	(101,354	)	$	277,227


	June 30, 2009			December 31, 2008
	(in thousands)
Segment Assets:
United States	$	8,320,069		$	8,524,622
South Africa		207,418			241,619
Tunisia		289,212			299,168
Headquarters		56,143			96,376

Total consolidated assets	$	8,872,842		$	9,161,785

NOTE M.

Impairment of Oil and Gas Properties

Oil and gas properties assessments. During the first quarter of 2009, the downward adjustments to economically recoverable resource potential in the Company’s Uinta/Piceance area associated with declines in commodity prices and well performance led to the impairment of the net assets in the Company’s Uinta/Piceance area. The Company’s estimates of the undiscounted future cash flows attributed to the assets indicated that their carrying amounts were not expected to be recovered. Consequently, the Company recorded a $21.1 million noncash charge during the first quarter of 2009 to reduce the carrying value of the Uinta/Piceance area oil and gas properties. The impairment charge reduced the oil and gas properties’ carrying values to their estimated fair values, represented by the estimated discounted future cash flows attributable to the assets, which were derived from Level 2 fair value inputs.

The Company’s primary assumptions of the estimated future cash flows attributable to oil and gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves and (ii) management’s commodity price outlook.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

Goodwill assessments. In accordance with SFAS 142, the Company assesses its goodwill for impairment annually during the third quarter using a July 1 assessment date. The Company’s assessment of goodwill during the third quarter of 2008 indicated that it was not impaired. As a result of declines in commodity prices and a significant decline in the Company’s market capitalization during the second half of 2008, which the Company considered an event that might indicate impairment to the carrying value of goodwill, the Company has reassessed whether the fair value of its net assets supported the carrying value of the Company’s goodwill at its United States reporting unit at December 31, 2008 and quarterly thereafter. The Company’s quarterly reassessments have indicated that its goodwill was not impaired.

The Company’s assessments of goodwill for impairment include estimates of the fair value of its United States reporting unit and comparisons of those fair value estimates with the United States reporting unit’s carrying value. The Company’s estimates of the fair value of its United States reporting unit entailed estimating the fair values of the reporting unit’s assets and liabilities. The primary component of those assets and liabilities is comprised of the reporting unit’s oil and gas properties, whose estimated values were based on the estimated discounted future net cash flows expected to be recovered from the properties. The Company’s primary assumptions in preparing the estimated discounted future net cash flows expected to be recovered from the properties are based on (i) proved reserves and risk-adjusted probable reserves, (ii) management’s price outlook, including assumptions as to inflation of costs and expenses, (iii) the Company’s weighted average cost of capital and (iv) future income tax expense attributable to the net cash flows.

Due to the significant decline in the Company’s market capitalization, the Company expanded its assessment of goodwill impairment to consider the fair value of the United States reporting unit as determined using both the previously described discounted future net cash flow approach and a market approach. The Company assessed market capitalization over the 30-day and 60-day periods prior to June 30, 2009, March 31, 2009 and December 31, 2008 and performed sensitivity valuations of the United States reporting unit’s net assets based on varying valuation combinations of future discounted cash flow assumptions (including assessing future cash flows from proved properties only), market capitalization, control premiums, price inflation assumptions and discount rate assumptions. Those assessments indicated that the United States goodwill was not impaired as of June 30, 2009, March 31, 2009 and December 31, 2008. The Company will continue to assess its goodwill for impairment and such assessments may be affected by (i) additional United States reserve adjustments, both positive and negative, (ii) results of drilling activities, (iii) changes in management’s outlook on commodity prices and costs and expenses, (iv) changes in the Company’s market capitalization, (v) changes in the Company’s weighted average cost of capital and (vi) changes in income taxes.

NOTE N.

Volumetric Production Payments

During 2005, the Company sold 27.8 MMBOE of proved reserves by means of three VPP agreements for net proceeds of $892.6 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPPs were used to reduce outstanding indebtedness. The first VPP sold 58 Bcf of gas volumes over an expected five-year term that began in February 2005. The second VPP sold 10.8 MMBbls of oil volumes over an expected seven-year term that began in January 2006. The third VPP sold 6.0 Bcf of gas volumes over an expected 32-month term from May 2005 through December 2007, and 6.2 MMBbls of oil volumes over an expected five-year term that began in January 2006.

The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests, (ii) are free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the reserves acquired), (iv) transfer title of the reserves to the purchaser and (v) allow the Company to retain the remaining reserves after the VPPs volumetric quantities have been delivered.

Under SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” a VPP is considered a sale of proved reserves. As a result, the Company (i) removed the proved reserves associated with the VPPs, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil and gas revenues over the term of each VPP, (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

The following table provides information about the deferred revenue carrying values of the Company’s VPPs.


	Gas			Oil			Total
	(in thousands)

Deferred revenue at December 31, 2008	$	49,435		$	275,706		$	325,141
Less: 2009 amortization		(24,514	)		(49,180	)		(73,694	)


Deferred revenue at June 30, 2009	$	24,921		$	226,526		$	251,447

The above deferred revenue amounts will be recognized in oil and gas revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):


Remaining 2009	$	74,212
2010		90,215
2011		44,951
2012		42,069

	$	251,447

NOTE O.

Interest and Other Income

The following table provides the components of the Company’s interest and other income:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009		2008
	(in thousands)

Alaskan Petroleum Production Tax credits (a)	$	87,511		$	6,605		$	94,989	$	17,770
Interest income		749			376			1,379		860
Other income		795			437			959		1,769
Deferred compensation plan income		74			174			861		1,546
Foreign currency remeasurement and exchange gains (b)		(735	)		(988	)		617		2,526
Credit card rebate		204			285			453		554
Change in asset retirement estimate		—			—			—		4,391
Legal settlements		—			(2	)		—		2,495

Total interest and other income	$	88,598		$	6,887		$	99,258	$	31,911

(a)	The Company earns Alaskan Petroleum Production Tax (“PPT”) credits on qualifying capital expenditures. The Company recognizes income from PPT credits at the time they are realized through a cash refund or sale.

(b)	The Company’s operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE P.

Other Expense

The following table provides the components of the Company’s other expense:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Idle rig related costs (a)	$	22,632		$	6,975		$	42,918		$	14,836
Transportation commitment loss (b)		6,781			—			6,781			—
Contingency and environmental accrual adjustments		262			63			6,086			507
Well servicing operations (c)		2,391			895			5,382			1,638
Foreign currency remeasurement and exchange losses (d)		3,408			(35	)		4,733			338
Inventory impairment (e)		433			—			1,603			—
Other		866			(882	)		1,345			(357	)
Bad debt expense		(58	)		1,259			(744	)		3,228

Total other expense	$	36,715		$	8,275		$	68,104		$	20,190

(a)	Represents stacked drilling rig costs under contractual drilling rig commitments and costs incurred to terminate contractual drilling rig commitments prior to their contractual maturities.

(b)	Primarily represents transportation contract deficiency payment obligations not supported by future production.

(c)	Represents idle well servicing costs.

(d)	The Company’s operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

(e)	Represents impairment charges to reduce the carrying value of excess lease and well equipment and supplies inventories to their estimated net realizable values.

NOTE Q.

Insurance Claims

As a result of Hurricane Rita in September 2005, the Company’s East Cameron facility, located in the Gulf of Mexico shelf, was destroyed. As of June 30, 2009, the Company estimated that it will cost approximately $16 million to $21 million to complete the reclamation and abandonment of the East Cameron facility. The operations to reclaim and abandon the East Cameron facilities began in January 2007. The estimate of the remaining costs to reclaim and abandon the East Cameron facility is based upon an estimate by the Company.

The remaining estimated cost to reclaim and abandon the East Cameron facilities contains a number of assumptions that could cause the ultimate cost to be higher or lower than the estimate, as there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. The Company has expended approximately $182.0 million on the reclamation and abandonment of the East Cameron facility through June 30, 2009. During the three months ended June 30, 2009, the Company recorded a $15.0 million noncash charge to hurricane activity, net in the accompanying statements of operations to increase its estimate of the total costs to reclaim and abandon the East Cameron facility.

The Company filed a claim with its insurance providers regarding the loss at East Cameron. Under the Company’s insurance policies, the East Cameron facility had the following coverages: (a) $14 million of scheduled property value for the platform, which was received in 2005, (b) $4 million of scheduled business interruption insurance after a deductible waiting period, which was received in 2006, (c) $100 million of well restoration and safety, in total, for all assets per occurrence and (d) $400 million for debris removal coverage for all assets per occurrence.

For the six months ended June 30, 2009, the Company has received $11.6 million from one of its insurance providers related to debris removal, which reduced the Company’s recorded receivable. At the present, no recoveries have been reflected related to certain costs associated with plugging and abandonment and the well restoration and safety coverages. In 2007, the Company commenced legal actions against its insurance carriers regarding policy

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

coverage issues, primarily related to debris removal, certain costs associated with plugging and abandonment, and the well restoration and safety coverages. The Company continues to expect that a substantial portion of the loss will be recoverable from insurance.

NOTE R.

Discontinued Operations

During the three months ended June 30, 2009, the Company committed to a plan to sell its shelf properties in the Gulf of Mexico and sold its Mississippi assets. The Company completed the sale of its shelf properties in the Gulf of Mexico on August 6, 2009. Pursuant to SFAS 144, the Company has reflected the results of operations of these transactions as discontinued operations, rather than as a component of continuing operations. Additionally, in April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries. During the three and six months ended June 30, 2008, the Company continued to realize certain revenues and costs and expense increments associated with these divestitures. The following table represents the components of the Company’s discontinued operations for the three and six month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in thousands)

Revenues and other income:
Oil and gas	$	5,736		$	18,186		$	11,722		$	34,619
Interest and other		—			86			—			1,989
Gain (loss) on disposition of assets, net (a)		306			(72	)		306			(6	)

		6,042			18,200			12,028			36,602

Costs and expenses:
Oil and gas production		2,109			1,469			4,649			3,275
Production and ad valorem taxes		60			74			118			214
Depletion, depreciation and amortization (a)		(551	)		2,428			3,862			7,418
Exploration and abandonments (a)		22			3,980			283			5,472
General and administrative		(21	)		(2	)		(36	)		215
Accretion of discount on asset retirement obligations (a)		220			199			442			398
Other		—			(433	)		—			(389	)

		1,839			7,715			9,318			16,603


Income from discontinued operations before income taxes		4,203			10,485			2,710			19,999
Income tax benefit (provision):
Current		—			348			—			(171	)
Deferred (a)		(1,472	)		(3,482	)		(949	)		(5,437	)

Income from discontinued operations	$	2,731		$	7,351		$	1,761		$	14,391

(a)	Represents the significant noncash components of discontinued operations.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

At June 30, 2009, the carrying values of the assets and liabilities of the Company’s Gulf of Mexico shelf operations are included in discontinued operations held for sale in the accompanying consolidated balance sheet and are comprised of the following (in thousands):


Composition of assets included in discontinued operations held for sale:
Current assets	$	2,870
Property, plant and equipment, net		13,385
Other assets, net		619

Total assets	$	16,874


Composition of liabilities included in discontinued operations held for sale (a):
Current liabilities	$	2,850
Other liabilities		13,856

Total liabilities	$	16,706

(a)	Asset retirement obligations comprised $1.3 million of current liabilities and $13.0 million of other liabilities.

NOTE S.

Subsequent Events

In accordance with SFAS 165, the Company has evaluated subsequent events through August 7, 2009, the date of issuance of the unaudited consolidated financial statements. The Company is not aware of any reportable subsequent events through August 7, 2009, except as disclosed in Notes J and R.

PIONEER NATURAL RESOURCES COMPANY

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Financial and Operating Performance

The Company’s financial and operating performance for the second quarter of 2009 included the following highlights:

•

Earnings attributable to common stockholders was a net loss of $91.6 million ($0.80 per diluted share), as compared to net income attributable to common stockholders of $156.7 million ($1.29 per diluted share) for the second quarter of 2008. The decrease in earnings attributable to common stockholders is primarily due to:

•

A decline in oil and gas revenues due to commodity price declines since the first half of 2008,

•

$181.9 million of second quarter 2009 unrealized derivative losses recorded under the mark-to-market accounting method and

•

Negative reserve price revisions associated with the commodity price declines, which increased depreciation, depletion and amortization expense, partially offset by

•

An $80.9 million increase in pretax Alaskan Petroleum Production Tax income and

•

Oil and gas production cost declines resulting from the Company’s cost reduction initiatives.

•

Daily sales volumes from continuing operations increased on a per-BOE basis by three percent to 115,436 BOEPD during the second quarter of 2009, as compared to 112,082 BOEPD during the second quarter of 2008. Approximately 2,000 BOEPD of production was shut in during the second quarter of 2009 as a result of unplanned third-party pipeline repairs in Alaska and the Mid-Continent area.

•

Average reported oil, NGL and gas prices from continuing operations decreased during the second quarter of 2009 to $70.89 per Bbl, $26.78 per Bbl and $3.43 per Mcf, respectively, as compared to respective prices of $88.27 per Bbl, $56.28 per Bbl and $8.70 per Mcf during the second quarter of 2008.

•

Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing operations decreased during the second quarter of 2009 to $8.07 and $2.26, respectively, as compared to respective costs of $9.54 and $4.47 during the second quarter of 2008, primarily as a result of cost reduction initiatives and commodity price declines.

•

Net cash provided by operating activities decreased by $109.2 million to $223.9 million for the second quarter of 2009, as compared to $333.1 million in the comparable quarter of 2008, primarily due to the decrease in oil and gas revenue.

Recent Events

Financial markets. During the second half of 2008, worldwide financial markets experienced significant turmoil as a result of a worldwide economic slowdown and a significant decline in the availability of liquidity provided by the financial markets. While these conditions have continued through the first half of 2009, the availability of liquidity in the financial markets saw some improvement during the second quarter of 2009. In response to the economic slowdown, governments worldwide have taken steps to enhance confidence and support the financial markets. The success of the steps taken and the duration of the uncertainty in the financial markets cannot be predicted. The Company is closely monitoring the economic environment, including changes in energy demand and fluctuations in commodity prices, the impact of which is mitigated by the Company’s derivative price risk activities. Depending on the severity and duration of the worldwide economic decline, these market conditions could negatively impact the Company’s liquidity, financial position and future results of operations. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information about the Company’s derivative contracts.

As of June 30, 2009, the Company had $64.3 million of cash on hand and $472.0 million of liquidity under its Credit Facility that matures in 2012. As of June 30, 2009, the Company also had $152.2 million of third-party accounts receivables and was a party to derivative financial instruments, of which approximately $104.2 million represent assets. Management is closely monitoring the credit standings of its customers; counterparties, including its banks; derivative counterparties and purchasers of the commodities the Company produces and sells.

The Company’s Credit Facility is subject to certain covenants, including the maintenance of a ratio of the net present value of the Company’s oil and gas properties to total debt (the “PV Ratio”). Effective April 29, 2009, the Company and its lenders amended the Credit Facility to provide the Company additional financial flexibility if longer-term commodity prices were to significantly deteriorate from current levels. The amendment reduced the required PV Ratio from 1.75 to 1.0 to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio reverts to 1.75 to 1.0, and provides that the Company may include in the PV Ratio calculation 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest. As of June 30, 2009, the Company was in compliance with all of its debt covenants.

The amendment also adjusted borrowing rates and commitment fees under the Credit Facility and changed certain provisions relating to the consequences if a lender under the Credit Facility defaults in its obligations under the agreement. See Note H of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for a discussion of the borrowing rates and commitment fees under the amended Credit Facility terms. The Company paid $4.5 million of issuance costs to complete the Credit Facility amendment during the second quarter of 2009.

PIONEER NATURAL RESOURCES COMPANY

Commodity prices. The economic slowdown in the United States and other industrialized countries has further resulted in significant reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the rise in domestic unconventional gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply resulted in significant declines in oil, NGL and gas prices during the second half of 2008. Since the end of 2008, oil prices have strengthened as supply and demand fundamentals have modestly improved while NGL prices have generally stabilized at year-end 2008 levels and gas prices have further deteriorated since year-end 2008 due to record storage levels, reflecting decreased industrial demand and generally mild weather conditions across the U.S. limiting electrical demand for summer cooling. Although the Company has entered into derivative contracts on a large portion of its production volumes through 2011, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company’s internal cash flows would be reduced for affected periods. The timing and magnitude of commodity price declines or recoveries cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows.

Cost reduction initiatives. During the fourth quarter of 2008, the Company implemented initiatives to reduce capital spending, operating costs and administrative expenses to support its goal of delivering net cash flow from operating activities in excess of capital requirements in 2009 and to enhance financial flexibility. This plan includes minimizing drilling activities until margins improve as a result of (i) commodity prices increasing and/or (ii) well cost reductions. As a result, the Company has significantly reduced its rig activity and has realized and continues to pursue reductions in operating expenses and well costs to align costs with the lower commodity price environment that currently exists. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and Barnett Shale areas and in Tunisia. Since the third quarter of 2008, when drilling and completion costs peaked, the Company has achieved an average reduction of approximately 30 percent in the cost of drilling and completing a well. The Company’s asset teams have also implemented initiatives that have reduced 2009 lease operating expense from continuing operations by 23 percent since the fourth quarter of 2008. The cost savings reflect cost reductions in electricity, water disposal and compression rental costs while expanding its use of internal well services. During the second quarter of 2009, the Company achieved a 14 percent reduction in lease operating expense per BOE from continuing operations as compared to the second quarter of 2008.

The Company’s 2009 capital budget is expected to be approximately $300 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs), representing a 76 percent decrease from actual 2008 annual capital costs. During the first half of 2009, the Company’s capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $162 million, as compared to $639 million during the first half of 2008, representing a 75 percent decrease. Capital expenditures for 2009 were heavily weighted to the first half of the year, when the Company completed wells in progress at year end 2008, finished previously scheduled drilling in Tunisia and further curtailed drilling activity in response to declining commodity prices during the first quarter of 2009.

SemGroup receivables. The Company was a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries (collectively, “SemGroup”), which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008 in the U.S. Bankruptcy Court for the District of Delaware. SemGroup purchased condensate from the Company and, at the time of the bankruptcy filings, was indebted to the Company for $29.6 million. The Company believed that it was probable that the collection of the pre-petition claims would not occur for a protracted period of time and that some of its claims may become uncollectible. Consequently, the Company recorded a bad debt expense of $19.6 million during the second half of 2008, which reduced the carrying value of the claims to $10.0 million.

PIONEER NATURAL RESOURCES COMPANY

Third Quarter 2009 Outlook

Based on current estimates, the Company expects that third quarter 2009 production from continuing operations will average 110,000 to 115,000 BOEPD. The range reflects the variability in the timing of oil cargo shipments in Tunisia.

Third quarter production costs from continuing operations (including production and ad valorem taxes and transportation costs) are expected to average $10.00 to $11.00 per BOE based on NYMEX strip prices for oil, NGLs and gas at the time of the estimate. Depletion, depreciation and amortization (“DD&A”) expense is expected to average $15.50 to $16.50 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $15 million to $25 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs. General and administrative expense from continuing operations is expected to be $33 million to $37 million. Interest expense is expected to be $42 million to $45 million, reflecting the higher borrowing costs associated with the Company’s April 2009 amendment to the Credit Facility. Accretion of discount on asset retirement obligations from continuing operations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ net income is expected to be $4 million to $7 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company also expects to recognize $10 million to $15 million of charges in other expense associated with certain drilling rigs being stacked as a result of the Company’s reduced capital expenditures budget.

The Company’s third quarter effective income tax rate is expected to range from 40 percent to 50 percent, assuming current capital spending plans, higher tax rates in certain foreign jurisdictions and no significant mark-to-market changes in the Company’s derivative position. Cash income taxes are expected to range from $5 million to $10 million, principally related to Tunisian income taxes.

Third quarter 2009 amortization of deferred hedge gains on discontinued and terminated oil and gas hedges is expected to be $22 million.

Operations and Drilling Highlights

The Company intends to limit 2009 capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, to internally-generated operating cash flow. During the six month period ended June 30, 2009, the Company’s capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, were approximately $162 million. If internal cash flows do not meet the Company’s expectations, the Company may further reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its Credit Facility, issuances of debt or equity securities or from other sources, such as asset sales.

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes by geographic area the Company’s finding and development costs incurred during the six month period ended June 30, 2009:


	Acquisition Costs					Exploration Costs		Development Costs			Asset Retirement Obligations		Total
	Proved		Unproved			Exploration Costs		Development Costs			Asset Retirement Obligations		Total
	(in thousands)

United States:
Permian Basin	$	3,330	$	5,594		$	4,423	$	64,753		$	1	$	78,101
Mid-Continent		—		—			206		766			—		972
Rocky Mountains		32		613			7,410		17,784			—		25,839
Barnett Shale		201		(47	)		6,593		321			—		7,068
Gulf of Mexico		—		—			203		(21	)		—		182
South Texas		2,688		8,141			16,054		(175	)		327		27,035
Alaska		—		(347	)		2,191		46,305			38		48,187

		6,251		13,954			37,080		129,733			366		187,384

South Africa		—		—			289		902			—		1,191
Tunisia		—		—			11,390		6,663			—		18,053
Other		—		—			583		—			—		583

		—		—			12,262		7,565			—		19,827

Total Worldwide	$	6,251	$	13,954		$	49,342	$	137,298		$	366	$	207,211

The following table summarizes the Company’s development and exploration/extension drilling activities for the six months ended June 30, 2009:


	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
United States	7	16	20	—	3


	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
United States	10	3	4	1	8
Tunisia	5	—	—	2	3

Total Worldwide	15	3	4	3	11

Permian Basin area. In the Spraberry field, production averaged 31,616 BOEPD and 34,370 BOEPD during the three and six month periods ended June 30, 2009, respectively, representing respective increases of two percent and 12 percent, as compared to the same periods of 2008. As a result of the Company’s reduced 2009 capital budget, the Company drilled no additional wells in the Spraberry field during the three months ended June 30, 2009. The Company’s cumulative 2009 well count in the Spraberry field totals 17 wells. Under a reduced drilling program for 2009, the Company expects to drill a total of 27 wells, primarily to protect leasehold rights, with plans to resume drilling with one rig during August. The majority of these Spraberry wells will be drilled deeper to add the Wolfcamp formation, which provides incremental production and proved reserves. Substantial declines in well costs, new oil price derivatives and forward market prices for oil exceeding $70 per Bbl are supportive of the Company’s plan to recommence drilling during August 2009 and into 2010.

During 2008, the Company initiated a program to test 20-acre well down spacing performance as part of its announced recovery improvement initiatives, which also include secondary recovery waterflood projects, shale/silt interval testing and horizontal well initiative opportunities in the Spraberry field. The Company continues to monitor the 20-acre pilot wells and their offsets with available data. The Company drilled a total of twenty 20-acre wells prior to 2009. With all 20 wells on production, the results are encouraging and will continue to be monitored before determining future plans for 20-acre drilling.

PIONEER NATURAL RESOURCES COMPANY

The Company expects to increase drilling in 2010, utilizing 10 to 12 drilling rigs. The Company also plans to implement a full-scale waterflood project in 2010.

The 20-acre well spacing and other initiatives described above are being performed to enhance hydrocarbon recovery, as a percentage of oil in place, in those areas of the Spraberry field that are expected to be conducive for these undertakings. However, the ultimate incremental recovery rates associated with these initiatives cannot be predicted at this time.

Mid-Continent area. In the Hugoton and West Panhandle fields, 2009 daily production averaged 17,617 BOEPD and 18,486 BOEPD during the three and six month periods ended June 30, 2009, respectively, representing respective decreases of 12 percent and eight percent, as compared to the same periods of 2008. Second quarter 2009 production was negatively impacted by unplanned third-party pipeline repairs. The Company continues to achieve production benefits in both the Hugoton and West Panhandle fields through gathering system efficiencies and improved system surveillance.

In the Hugoton field, the Company has completed its testing of both re-completed and new drill wells that are commingled in the Chase and Council Grove formations. Future development plans will incorporate further expansion of this activity in the field. Additional gathering system improvements are planned to begin in late-2009.

In the West Panhandle field, the Company is not planning any 2009 development drilling in support of the Company’s cost reduction initiatives. The Company is planning to maximize operating results in the field through well recompletions, fracture stimulations and continued replication of its successful lateral well cleanout program.

Rocky Mountain area. The Company’s Raton Basin production volumes averaged 31,371 BOEPD and 31,884 BOEPD during the three and six month periods ended June 30, 2009, respectively, representing respective declines of seven percent and four percent, as compared to the same periods of 2008. No drilling or completion work was conducted in the first half of 2009. The Company was able to maintain relatively stable production, with low rates of decline, through initiatives such as compressor upgrades and modifications made at the Company’s compressor stations that occurred during the second quarter of 2009 and during 2008. In support of the Company’s cost reduction initiatives, efforts are underway in the Rocky Mountain area to reduce operating costs, including improving operational methods. The detailed basin-wide evaluation of data obtained from the 2008 Pierre Shale drilling program continues in conjunction with 2009 production and formation testing. Future drilling operations will resume once gas prices and drilling costs stabilize allowing the Company to achieve targeted rates of return.

South Texas area. In South Texas, the Company’s production volumes averaged 12,321 BOEPD and 13,632 BOEPD during the three and six months ended June 30, 2009, respectively, representing respective increases of four percent and 16 percent, as compared to the same periods of 2008. Pioneer continues to analyze and map its newly acquired 900 square mile 3-D data set in order to optimize future location selection. The Company has a substantial number of locations in inventory for development of the previously discovered Moray, Sawfish, Skipjack and Amberjack fields, as well as several as yet undrilled exploration prospects. Drilling activity in the Edwards play will resume when natural gas prices and margins increase to a level that provides adequate economic returns on drilling. In the mean time, the Company continues to maintain its strong position in South Texas through both the renewal of existing leases and the acquisition of new leases.

In the second quarter of 2009, the Company completed its first horizontal well in the Eagle Ford Shale play. The well, which initially encountered mechanical problems, had an initial flow rate of approximately 3.7 MMcf of gas equivalent per day, with production contributing from only two of five fracture stages. The Company is initiating a multi-well drilling program during the third quarter of 2009 to help delineate the play and assess its resource potential. The Eagle Ford Shale play is prospective over much of the 310,000 acres that the Company currently holds.

In order to accommodate its Edwards Trend and Eagle Ford Play growth, the Company added additional gas gathering and processing infrastructure during 2008. The expansion includes over 28 miles of gathering system pipeline, three additional operated gas treatment plants and two additional non-operated gas treatment plants.

Barnett Shale. In the Barnett Shale area of Texas, the Company’s production volumes averaged 3,186 BOEPD and 3,124 BOEPD during the three and six months ended June 30, 2009, respectively, representing respective increases of 52 percent and 43 percent, as compared to the same periods of 2008. During the second quarter of 2009, the Company continued to focus its efforts on improving operational performance including multiple successful well workovers and compressor optimization projects. The Company participated in two non-operated successful wells, with a third well drilling at quarter end, and is preparing to acquire additional 3-D seismic over a portion of its acreage.

PIONEER NATURAL RESOURCES COMPANY

Alaska area. During the first half of 2009, the Company continued drilling activities at its Oooguruk development project. The Company’s production from the project, which began in June 2008, averaged 3,377 BOPD and 3,632 BOPD during the three and six months ended June 30, 2009, respectively. Second quarter production from the project’s Kuparuk reservoir wells was curtailed by approximately 1,000 BOPD due to constraints in the third-party water delivery system that provides water for reservoir pressure management. Sufficient water injection volumes resumed during the second quarter. The Company is drilling five horizontal wells within the project’s Nuiqsut reservoir during the second and third quarters, of which three will be fracture-stimulated production wells and two will be unstimulated water injection wells. The first unstimulated water injector has been producing oil at a stabilized rate of approximately 1,000 BOPD and will be converted to injection during August. Early results from the first two fracture-stimulated production wells, which had a combined initial flow rate of 5,400 BOPD, suggest that stabilized production will be two-to-three times that of the unstimulated injector.

On the Company’s Cosmopolitan Unit project in the Cook Inlet, the Company drilled a lateral sidetrack during 2007 from an existing wellbore on an onshore site to further appraise the resource potential of the unit. The initial unstimulated production test results were encouraging. The Company will conduct permitting activities and facilities planning throughout 2009 and plans to drill another appraisal well in 2010.

South Africa. In South Africa, the Company’s production averaged 5,920 BOEPD and 5,608 BOEPD during the three and six month periods ended June 30, 2009, respectively, representing increases of 58 percent and 51 percent, as compared to the same periods of 2008. The substantial increases in production are reflective of the commencement of production from the most prolific well in Pioneer’s South Coast Gas project during the fourth quarter of 2008. First production from the Company’s Sable gas well was initiated in mid-October 2008 and the other wells in the South Coast Gas project resumed production in late-October. Second quarter 2009 production was curtailed slightly as a result of ongoing repairs to the operator’s onshore condensate facilities. The operator of the South Coast Gas project has notified the Company that a major plant turnaround is scheduled during the fourth quarter of 2009 at the Mossel Bay gas-to-liquids plant where the gas production is sold. The operator of the South Coast Gas project has notified the Company that a major plant turnaround is scheduled during the fourth quarter of 2009 at the Mossel Bay gas-to-liquids plant where the gas production is sold. As a result, fourth quarter forecasted production is expected to be reduced by approximately 2,000 BOEPD. In addition, the operator has also notified the Company that past production volumes reported for the South Coast Gas project were (in the operator’s view) overstated due to potential meter measurement errors. During June 2009, the operator commenced reporting volumes for the Company’s account from the South Coast Gas project at the reduced amount. The Company is awaiting further technical information from the operator in order to assess the extent of the errors, if any, and will be working closely with the operator and metering specialists during the second half of 2009 to validate the operator’s position and better understand any metering errors to ensure that the Company has received (and will receive) its appropriate share of gas production from the South Coast Gas project. The Company does not expect that the resolution of this matter will have a material impact on its liquidity, results of operations or financial position.

Tunisia. The Company’s two production concessions in Southern Tunisia averaged 7,447 BOEPD and 7,095 BOEPD of production during the three and six month periods ended June 30, 2009, respectively, representing respective increases of nine percent and 29 percent, as compared to the same periods of 2008. In the Cherouq Concession, first sales occurred during the first quarter of 2008 and gross cumulative production through the end of the second quarter of 2009 exceeded 4.3 million barrels. During 2009, the Company plans to complete the processing of the 295 square kilometers of 3-D seismic data acquired in 2008. The geosciences work program will include the integration of existing geologic data sets into a comprehensive basin modeling project targeted at reducing uncertainty and high-grading prospective exploration and development locations. Additionally, the Company has upgraded its existing production facilities by installing permanent equipment that is expected to reduce production costs.

During 2009, the Company plans to continue its exploratory and appraisal activities on the Adam Concession by participating in up to three non-operated wells commencing in the third quarter. The Company also plans to begin a 3-D seismic acquisition program on the Borj El Khadra Permit in 2010.

In the Anaguid permit during 2008, the Company acquired an additional 900 square kilometers of 3-D seismic data and drilled one successful exploration well. The Company plans to complete the processing and interpretation of the seismic data and drill an additional exploration well in late 2009 or early 2010.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $370.7 million and $738.5 million for the three and six months ended June 30, 2009, as compared to $635.1 million and $1.2 billion for the same respective periods of 2008.

PIONEER NATURAL RESOURCES COMPANY

The decrease in oil and gas revenues from continuing operations during the three and six months ended June 30, 2009, as compared to the same periods of 2008, is reflective of decreases in revenues for all geographic operating segments. The decrease in revenues in the United States was due to decreases in average reported oil, NGL and gas prices, partially offset by sales volume increases resulting from successful 2008 drilling activity, sales of approximately 2,500 BOEPD of NGLs that were in storage as of December 31, 2008 and reductions in scheduled VPP deliveries. Revenues in Tunisia decreased due to decreases in average reported oil and gas prices, partially offset by oil and gas sales volume increases due to successful drilling programs. Revenues in South Africa decreased due to decreases in average reported oil and gas prices, partially offset by a gas sales volume increase due to the initiation of gas production from the Sable field in the fourth quarter of 2008.

The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
Oil (Bbls):
United States	23,873	19,829	25,109	19,966
South Africa	379	2,819	312	2,821
Tunisia	7,154	6,370	6,754	5,136

Worldwide	31,406	29,018	32,175	27,923

NGLs (Bbls):
United States	18,921	20,464	20,778	19,914

Gas (Mcf):
United States	355,661	367,414	370,565	365,983
South Africa	33,243	5,570	31,771	5,322
Tunisia	1,753	2,619	2,048	2,098

Worldwide	390,657	375,603	404,384	373,403

Total (BOE):
United States	102,069	101,529	107,647	100,877
South Africa	5,920	3,747	5,608	3,708
Tunisia	7,447	6,806	7,095	5,486

Worldwide	115,436	112,082	120,350	110,071

The following table provides average daily sales volumes from discontinued operations, by geographic area and in total, for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
Oil (Bbls):
United States	868	1,211	983	1,264

NGLs (Bbls):
United States	29	45	37	44

Gas (Mcf):
United States	3,276	3,893	3,271	4,580

Total (BOE):
United States	1,443	1,905	1,564	2,071

On a quarter-to-quarter BOE comparison, average daily sales volumes increased by one percent in the United States, by 58 percent in South Africa and by nine percent in Tunisia. For the six months ended June 30, 2009, as compared to the six months ended June 30, 2008, average daily BOE sales volumes increased by seven percent in the United States, by 51 percent in South Africa and by 29 percent in Tunisia.

PIONEER NATURAL RESOURCES COMPANY

During the three and six month periods ended June 30, 2009, as compared to the three and six month periods ended June 30, 2008, oil volumes delivered under the Company’s VPPs decreased by 38 MBbl (5 percent) and 80 MBbl (6 percent), respectively, while gas volumes delivered under the Company’s VPPs decreased by 228 MMcf (8 percent) and 483 MMcf (9 percent), respectively.

The oil, NGL and gas prices that the Company reports are based on the market price received for the commodities adjusted by the results of the Company’s cash flow hedging activities prior to February 1, 2009, and the amortization of deferred VPP revenue and AOCI – Hedging gains for hedges that were discontinued on January 31, 2009.

The following table provides average reported prices from continuing operations (including the results of hedging activities and the amortization of deferred VPP revenue) and average realized prices from continuing operations (excluding the results of hedging activities and the amortization of deferred VPP revenue) by geographic area and in total, for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Average reported prices:
Oil (per Bbl):
United States	$	75.13	$	70.50	$	64.39	$	69.43
South Africa	$	62.27	$	131.23	$	56.33	$	116.34
Tunisia	$	57.23	$	124.58	$	52.57	$	115.00
Worldwide	$	70.89	$	88.27	$	61.83	$	82.55
NGL (per Bbl):
United States	$	26.78	$	56.28	$	24.69	$	55.10
Gas (per Mcf):
United States	$	3.24	$	8.65	$	3.82	$	8.18
South Africa	$	5.29	$	8.52	$	4.66	$	8.09
Tunisia	$	7.78	$	14.89	$	6.74	$	13.39
Worldwide	$	3.43	$	8.70	$	3.90	$	8.21
Average realized prices:
Oil (per Bbl):
United States	$	52.78	$	122.49	$	43.39	$	109.95
South Africa	$	62.27	$	131.23	$	56.33	$	116.34
Tunisia	$	57.23	$	124.58	$	52.57	$	115.00
Worldwide	$	53.91	$	123.80	$	45.44	$	111.52
NGL (per Bbl):
United States	$	25.42	$	57.10	$	23.45	$	55.71
Gas (per Mcf):
United States	$	2.79	$	9.51	$	3.17	$	8.42
South Africa	$	5.29	$	8.52	$	4.66	$	8.09
Tunisia	$	7.78	$	14.89	$	6.74	$	13.39
Worldwide	$	3.02	$	9.54	$	3.31	$	8.44

Derivative activities. The Company utilizes commodity swap and collar contracts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. Prior to February 1, 2009, the Company accounted for its derivative activity using hedge accounting, which requires that the effective portions of changes in the fair values of the Company’s commodity price hedges be deferred as increases or decreases to AOCI – Hedging until the underlying hedged transaction occurs. Consequently, changes in the effective portions of commodity price hedges added volatility to the Company’s reported stockholders’ equity until the hedge derivative either matured or was terminated. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments and since that date has accounted for its derivative instruments using the mark-to-market accounting method. During the three and six months ended June 30, 2009, the Company’s

PIONEER NATURAL RESOURCES COMPANY

commodity derivative hedges increased oil, NGL and gas revenues by $28.5 million and $69.9 million, respectively, as compared to having reduced oil, NGL and gas revenues by $163.6 million and $244.2 million during the same respective periods of 2008. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for the scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil and gas revenues.

Deferred revenue. During the three and six month periods ended June 30, 2009 and 2008, the Company’s amortization of deferred VPP revenue increased oil and gas revenues by $37.0 million and $73.7 million, respectively, as compared to increases of $39.5 million and $78.9 million during the same respective periods of 2008. See Notes G and N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s VPPs.

Interest and other income. Interest and other income for the three and six month periods ended June 30, 2009 was $88.6 million and $99.3 million, respectively, as compared to $6.9 million and $31.9 million for the same respective periods in 2008. The increases in interest and other income from continuing operations during the three and six months ended June 30, 2009, as compared to the same period in 2008, was primarily due to increases of $80.9 million and $77.2 million, respectively, in Alaskan petroleum production tax credits. See Note O of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding interest and other income.

Oil and gas production costs. The Company recorded oil and gas production costs of $84.8 million and $195.2 million during the three and six month periods ended June 30, 2009, respectively, as compared to $97.3 million and $190.1 million during the same respective periods of 2008. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE from continuing operations decreased by 15 percent and six percent during the three and six month periods ended June 30, 2009, as compared to the same periods in 2008. During 2008, the Company’s oil and gas production costs increased throughout the first nine months of the year, primarily due to inflation of well servicing expense, electricity expense and water hauling costs. As a result of the Company’s cost reduction initiatives that were started in late 2008 and continue in 2009, Pioneer has realized significant production cost reductions during the first half of 2009 as compared to similar costs in 2008 and anticipates additional cost savings in future periods. The decrease in South Africa production costs is directly attributable to the shut in of the Sable oil field, which had a high fixed-cost component of production costs as compared to the South Coast Gas project, which has significantly lower production costs. The increase in Tunisia production costs is associated with the start-up of Cherouq production using rental facilities. Tunisia production costs are expected to decline based on the recent installation of permanent facilities.

The following tables provide the components of the Company’s oil and gas production costs per BOE from continuing operations and total production costs per BOE from continuing operations by geographic area for the three and six month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Lease operating expenses	$	6.58	$	8.06		$	7.17	$	7.77
Third-party transportation charges		0.94		1.11			0.94		1.06
Net natural gas plant/gathering charges		0.07		(0.37	)		0.29		(0.06	)
Workover costs		0.48		0.74			0.55		0.72


Total production costs	$	8.07	$	9.54		$	8.95	$	9.49

PIONEER NATURAL RESOURCES COMPANY


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
United States	$	8.11	$	8.98	$	8.91	$	8.85
South Africa	$	0.83	$	24.54	$	3.88	$	27.19
Tunisia	$	13.22	$	9.72	$	13.85	$	9.27
Worldwide	$	8.07	$	9.54	$	8.95	$	9.49

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $23.7 million and $51.4 million during the three and six month periods ended June 30, 2009, respectively, as compared to $45.7 million and $83.5 million for the same respective periods of 2008. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. Consequently, during the three and six month periods ended June 30, 2009, the Company’s production taxes have declined 73 percent and 67 percent, respectively, reflecting the year-to-year decline in commodity prices, while ad valorem taxes have increased slightly.

The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for the three and six month periods ended June 30, 2009 and 2008:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Ad valorem	$	1.44	$	1.41	$	1.43	$	1.37
Production		0.82		3.06		0.93		2.80


Total ad valorem and production taxes	$	2.26	$	4.47	$	2.36	$	4.17

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $165.9 million ($15.80 per BOE) and $354.1 million ($16.26 per BOE) for the three and six month periods ended June 30, 2009, respectively, as compared to $112.3 million ($11.01 per BOE) and $216.9 million ($10.83 per BOE) during the same respective periods of 2008. The increase in DD&A expense during the three- and six-month periods ended June 30, 2009, as compared to the same respective period of 2008, is primarily due to an increase in depletion of oil and gas properties.

Depletion expense was $15.11 per BOE and $15.59 per BOE during the three and six months ended June 30, 2009, as compared to $10.30 per BOE and $10.10 per BOE during the same respective periods of 2008. The 47 percent and 54 percent increases in per BOE depletion expense during the three and six months ended June 30, 2009 is primarily due to (i) losing end-of-life reserves that became uneconomic as a result of lower commodity prices at March 31, 2009 and June 30, 2009, (ii) a generally increasing trend through 2008 in the Company’s oil and gas properties’ cost bases per BOE of proved and proved developed reserves as a result of cost inflation in drilling rig rates and drilling supplies and (iii) the relatively higher depletion rate per BOE associated with production from the Oooguruk development, which began first production in June 2008, and South African South Coast Gas project, which became fully operational in October 2008.

Since the second half of 2008, the Company’s proved reserves have been negatively impacted by commodity price declines. See “Recent Events” for additional information regarding commodity price declines.

PIONEER NATURAL RESOURCES COMPANY

The following table provides depletion expense per BOE from continuing operations by geographic area for the three and six months ended June 30, 2009 and 2008:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008

United States	$	14.26	$	10.47	$	15.01	$	10.24
South Africa	$	37.95	$	13.64	$	36.45	$	13.40
Tunisia	$	8.48	$	5.90	$	7.84	$	5.39
Worldwide	$	15.11	$	10.30	$	15.59	$	10.10

Impairment of oil and gas properties and other assets. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. During the six months ended June 30, 2009, the Company recognized impairment charges of $21.1 million to reduce the carrying value of the Company’s oil and gas properties in the Uinta/Piceance areas. The continued declines in gas prices and downward adjustments to the economically recoverable resource potential during the first quarter of 2009 led to the impairment charge.

Commodity price declines during the second half of 2008 provided indications that the Company’s $310.6 million carrying value of goodwill may have been impaired as of December 31, 2008. The Company assessed the carrying value of goodwill for impairment as of December 31, 2008, March 31, 2009 and June 30, 2009 and found it not to be impaired. However, goodwill remains at risk for impairment in future periods if commodity prices decline further or if other impairment indicators were to erode. See Note M of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s impairment assessments and the primary factors that impact the Company’s assessments of goodwill and oil and gas properties for impairment.

Exploration and abandonments expense. The following tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for the three and six months ended June 30, 2009 and 2008 (in thousands):


	United States			South Africa		Tunisia			Other		Total
Three Months Ended June 30, 2009
Geological and geophysical	$	9,305		$	195	$	1,841		$	201	$	11,542
Exploratory dry holes		2,824			—		1,403			—		4,227
Leasehold abandonments and other		5,849			—		—			—		5,849

	$	17,978		$	195	$	3,244		$	201	$	21,618


Three Months Ended June 30, 2008
Geological and geophysical	$	19,119		$	3	$	2,916		$	2,767	$	24,805
Exploratory dry holes		(175	)		—		(29	)		149		(55	)
Leasehold abandonments and other		1,358			—		—			—		1,358

	$	20,302		$	3	$	2,887		$	2,916	$	26,108

PIONEER NATURAL RESOURCES COMPANY


	United States		South Africa		Tunisia		Other		Total
Six Months Ended June 30, 2009
Geological and geophysical	$	19,285	$	289	$	4,132	$	581	$	24,287
Exploratory dry holes		2,709		—		6,417		—		9,126
Leasehold abandonments and other		19,375		—		—		—		19,375

	$	41,369	$	289	$	10,549	$	581	$	52,788


Six Months Ended June 30, 2008
Geological and geophysical	$	40,284	$	52	$	11,750	$	5,163	$	57,249
Exploratory dry holes		1,114		—		1,251		443		2,808
Leasehold abandonments and other		3,236		—		—		—		3,236

	$	44,634	$	52	$	13,001	$	5,606	$	63,293

The Company’s exploration and abandonment expense during the three and six months ended June 30, 2009 is primarily attributable to continued seismic activity in the Company’s South Texas and Tunisian areas, geological and geophysical personnel costs, dry hole expense and unproved property abandonments. During the three months ended June 30, 2009, the Company’s exploration and abandonment expense included dry hole and leasehold abandonment expenses of $10.1 million, which is primarily comprised of $5.9 million of U.S. unproved property abandonments and $2.8 million and $1.4 million of dry hole provisions in the U.S. and Tunisia, respectively. During the six months ended June 30, 2009, the Company’s exploration and abandonment expense included dry hole and leasehold abandonment expenses of $28.5 million, which is primarily comprised of $19.4 million of U.S. unproved property abandonments and $6.4 million of dry hole provisions in Tunisia.

During the six months ended June 30, 2009, the Company drilled and evaluated seven exploration/extension wells, four of which were successfully completed as discoveries. During the same period in 2008, the Company drilled and evaluated 19 exploration/extension wells, 18 of which were successfully completed as discoveries. The decline in the number of exploration/extension wells drilled by the Company is primarily due to the Company’s significant reduction in its capital budget in support of cost reduction initiatives.

General and administrative expense. General and administrative expense for the three and six month periods ended June 30, 2009 were $33.3 million and $67.9 million, respectively, as compared to $35.6 million and $72.1 million during the same respective periods of 2008. The decrease in general and administrative expense was primarily due to a decline in bonus accrual compensation costs and legal fees, coupled with general cost savings associated with the Company’s costs reduction initiatives. Partially offsetting the Company’s cost reduction initiatives are increases in Pioneer Southwest administrative costs subsequent to its initial public offering on May 6, 2008.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.8 million and $5.5 million for the three and six month periods ended June 30, 2009, respectively, as compared to $2.0 million and $3.9 million during the same respective periods of 2008. The increase in accretion of discount on asset retirement obligations during 2009 is primarily due to the accretion of larger asset retirement obligations due to reserve reductions as well as new wells placed on production. See Note H of Notes to Consolidated Financial Statements in “Item 1. Financial Statements” for information regarding the Company’s asset retirement obligations.

Interest expense. Interest expense was $43.5 million and $84.6 million for the three and six month periods ended June 30, 2009, respectively, as compared to $41.7 million and $81.9 million during the same respective periods of 2008. The weighted average interest rate on the Company’s indebtedness for the three and six months ended June 30, 2009, including the effects of interest rate derivatives and capitalized interest was 5.5 percent and 5.4 percent as compared to 5.5 percent for the same respective periods of 2008.

Effective January 1, 2009, the Company adopted the provisions of FSP APB 14-1. The provisions of FSP APB 14-1 resulted in a retrospective adjustment to increase the Company’s 2008 interest expense for the three and six months ended June 30 by $3.4 million and $6.2 million, respectively, and increased the Company’s 2009 interest expense for the three and six months ended June 30 by $3.5 million and $7.0 million. See Notes B and F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s adoption of FSP APB 14-1.

PIONEER NATURAL RESOURCES COMPANY

The $1.8 million increase in interest expense during the three months ended June 30, 2009, as compared to the same period of 2008, was primarily due to a $2.4 million decrease in capitalized interest related to the Oooguruk project as development wells are placed on production, offset by the increase in interest expense associated with the adoption of FSP ABP 14-1. The $2.7 million increase in interest expense during the six months ended June 30, 2009, as compared to the same period of 2008, was primarily due to (i) a $5.8 million decrease in capitalized interest related to the Oooguruk project as development wells are placed on production and (ii) the increase in interest expense associated with the adoption of FSP ABP 14-1, partially offset by (iii) a $2.5 million decrease in cash interest expense on long-term borrowings.

Hurricane activity, net. The Company recorded net hurricane related activity expenses of $16.1 million and $16.5 million during the three and six month periods ended June 30, 2009, respectively, as compared to $1.4 million and $1.9 million during the same respective periods of 2008. Hurricane activity, net is associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, which was destroyed during 2005 by Hurricane Rita.

The Company estimates that it will cost approximately $16 million to $21 million to complete operations to reclaim and abandon the East Cameron platform facilities. Since January 2007, the Company has expended approximately $182.0 million on operations to reclaim and abandon the East Cameron platform facilities. The Company’s remaining estimate to reclaim and abandon the East Cameron facilities is based upon an analysis prepared by the Company. During 2007, the Company commenced legal actions against its insurance carriers regarding certain policy coverage issues. The Company continues to expect that a substantial portion of the loss will be recoverable by insurance. During the first half of 2009, the Company received $11.6 million of insurance recoveries associated with East Cameron facilities that reduced the Company’s recorded receivable for debris removal from one insurance carrier. See Note Q of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s East Cameron facility reclamation and abandonment.

Derivative losses, net. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments, and from that date forward has accounted for derivative instruments using the mark-to-market accounting method. Under the mark-to-market accounting method, the Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur. During the three months ended June 30, 2009, the Company’s commodity price derivatives increased derivative losses, net by $170.2 million, of which amount $181.9 million represented unrealized losses subject to continuing market risk, and $11.7 million represented realized gains. During the six months ended June 30, 2009, the Company’s commodity price derivatives increased derivative losses, net by $70.4 million, of which amount $107.5 million represented unrealized losses subject to continuing market risk, and $37.1 million represented realized gains.

Other expense. Other expense for the three and six months ended June 30, 2009 was $36.7 million and $68.1 million, respectively, as compared to $8.3 million and $20.2 million for the same respective periods of 2008. The $28.4 million increase in other expenses for the three months ended June 30, 2009, is primarily attributable to (i) a $15.7 million increase in stacked and termination charges associated with drilling rig commitments, (ii) a $6.8 million charge related to future commitment under transportation agreements and (iii) a prior year $4.3 million credit from legal settlements. The $47.9 million increase in other expenses for the six months ended June 30, 2009, is primarily attributable to (i) a $28.1 million increase in stacked and termination charges associated with drilling rig commitments, (ii) the aforementioned $6.8 million charge related to future commitments under transportation agreements, (iii) a $5.6 million increase in contingency and environmental accrual adjustments, (iv) the aforementioned prior year $4.3 million credit from legal settlements and (v) a $3.7 million increase in idle well servicing. See Note P of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.

Income tax provision. The Company recognized income tax benefits from continuing operations of $44.4 million and $45.1 million during the three and six months ended June 30, 2009, respectively, as compared to income tax provisions of $121.0 million and $204.5 million during the same respective periods of 2008. The decreases in income tax provisions during the three and six months ended June 30, 2009, as compared to the respective periods of 2008, were primarily due to decreases in income from continuing operations before income taxes, reflecting the significant decline in commodity prices and noncash derivative losses associated with mark-to-market accounting. The Company’s effective tax rate on continuing operations of 32 percent and 29 percent during the three and six months ended June 30, 2009, differs from the combined United States federal and state statutory rate of approximately 37 percent primarily due to:

•

foreign tax rates,

PIONEER NATURAL RESOURCES COMPANY

•

statutes in foreign jurisdictions that differ from those in the U.S.,

•

a U.S. loss being consolidated with income in certain foreign jurisdictions with higher tax rates and

•

expenses in foreign locations where the Company does not expect to receive income tax benefits, principally attributable to well costs in Tunisia.

The Company recognized a current foreign tax benefit of $9.2 million during three months ended June 30, 2009, as compared to a current foreign income tax provision of $25.4 million during the second quarter of 2008. The $34.9 million decrease is primarily due to (1) a $38.0 million decrease in taxable income in Tunisia and (2) the establishment of a $23.1 million investment reserve in Tunisia. On June 30, 2009, pursuant to Tunisian law, the Company established an investment reserve equal to 20 percent of 2008 taxable profits on the Adam and Cherouq concessions and thereby reduced current taxes payable $13.1 million. The investment reserve must be used to fund future exploration activity or pipeline infrastructure projects in Tunisia. No depreciation deduction is allowed for reserve funds used for exploration, therefore, future cash taxes may increase.

See Note E of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s income taxes.

Income from discontinued operations, net of tax. The Company reported income from discontinued operations, net of tax of $2.7 million and $1.8 million for the during the three and six month periods ended June 30, 2009, respectively, as compared to $7.4 million and $14.4 million for the same respective periods of 2008. See Note R of the Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s discontinued operations.

Net income attributable to noncontrolling interest. Net loss attributable to noncontrolling interest for the three month period ended June 30, 2009 was $522 thousand while the net income attributable to noncontrolling interest for the six month period ended June 30, 2009 was $3.3 million, as compared to net income attributable to noncontrolling interest of $6.2 million and $7.0 million for the same respective periods of 2008. The $6.7 million and $3.7 million decrease in net income attributable to noncontrolling interest is primarily due to noncontrolling interests in the first and second quarter 2009 net income (loss) of Pioneer Southwest. See Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding Pioneer Southwest and the Company’s noncontrolling interest in consolidated subsidiaries’ net income (loss).

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company’s primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas assets, payment of contractual obligations, dividends/distributions and working capital obligations. Funding for these cash needs, as well as funding for any stock or debt repurchases that the Company may undertake, may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in “Capital resources” below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internal operating cash flows and with its liquidity under its Credit Facility. Acquisitions may be funded with internal operating cash flows, the proceeds from debt or equity offerings or availability under the Company’s Credit Facility. Although the Company expects that internal operating cash flows will be adequate to fund capital expenditures and dividend/distribution payments, and that available borrowing capacity under the Company’s Credit Facility will provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs.

The worldwide economic slowdown has negatively impacted the demand for energy and as a result, commodity prices have declined significantly since their highs in mid-2008. As a result of the significant decline in commodity prices, the Company has implemented cost reduction initiatives to reduce capital spending, operating costs and general and administrative expenses to enhance and preserve financial flexibility. Specifically, the Company has reduced its rig activity to one rig operating in Alaska and one rig operating in the Spraberry field and has aggressively pursued reductions in operating and well costs to better align costs with the lower commodity price environment that currently exists. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and Barnett Shale areas and in Tunisia. The Company plans to minimize drilling activities until late 2009 or early 2010 at which time the Company is planning to resume its oil drilling program in the Spraberry field in West Texas and in Tunisia, and assess its gas resource potential in the Eagle Ford Shale play in South Texas.

PIONEER NATURAL RESOURCES COMPANY

The Company’s 2009 capital budget is limited to approximately $300 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs), representing a 76 percent decrease from actual 2008 annual capital costs. During the first half of 2009, the Company’s capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $162 million, as compared to $639 million during the first half of 2008, representing a 75 percent decrease. Capital expenditures during the first half of 2009 capital expenditures were front-end loaded as the Company completed wells in progress at year end 2008, finished previously scheduled drilling in Tunisia and further curtailed drilling activity in response to declining commodity prices during the first quarter of 2009.

Investing activities. Investing activities used $88.7 million and $259.8 million of cash during the three and six months ended June 30, 2009, respectively, as compared to $313.9 million and $491.5 million for the same respective periods of 2008. The $225.2 million decrease in net cash used in investing activities for the three month period ended June 30, 2009 is primarily due to a $241.7 million decrease in additions to oil and gas properties. The $231.7 million decrease in net cash used in investing activities for the six month period ended June 30, 2009 is primarily due to a $374.5 million decrease in additions to oil and gas properties, offset by a $142.0 million decrease in proceeds from the disposition of assets. During the three and six months ended June 30, 2009, the Company’s expenditures for additions to oil and gas properties were funded by $223.9 million and $248.3 million of net cash provided by operating activities, respectively, cash on hand and borrowings under the Company’s Credit Facility. During the three and six months ended June 30, 2008, the Company’s expenditures for additions to oil and gas properties were funded by $333.1 million and $510.7 million of net cash provided by operating activities, respectively, borrowings on the Company’s Credit Facility and $130.8 million of the remaining proceeds received in January 2008 from the sale of the Company’s Canadian assets in November 2007.

Dividends/distributions. During March 2009 and 2008, the Company’s board of directors (the “Board”) declared semiannual dividends of $0.04 per common share and $0.14 per common share, respectively. Associated therewith, the Company paid approximately $4.7 million and $16.9 million of aggregate dividends during April 2009 and 2008, respectively. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company’s liquidity and capital resources at the time.

During January and April 2009, the Pioneer Southwest board of directors (“Pioneer Southwest Board”) declared quarterly distributions of $0.50 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $4.7 million in each of February and May 2009. Future distributions are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the current distribution amount based on Pioneer Southwest’s liquidity and capital resources at the time.

Share repurchases. During February 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock. During the six months ended June 30, 2009 and 2008, the Company expended $16.3 million to acquire 1.0 million shares of treasury stock and $12.8 million to acquire 293 thousand shares of treasury stock, respectively, under share repurchase programs. As of June 30, 2009, $355.8 million of stock may be purchased in the future under the $750 million Board authorization.

Contractual obligations, including off-balance sheet obligations. The Company’s contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, other liabilities, transportation commitments and VPP obligations. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of June 30, 2009, the material off-balance sheet arrangements and transactions that the Company has entered into included (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling and transportation commitments, (iv) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future) and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. Since December 31, 2008, the material changes in the Company’s contractual obligations included a $69.0 million increase in outstanding long-term borrowings, a $73.7 million decrease in the Company’s VPP obligations, a $113.9 million increase in the Company’s net derivative liabilities and a decrease of approximately $42.9 million in the Company’s rig commitments. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on the Company’s long-term debt and a table of changes in the fair value of the Company’s open derivative obligations during the six months ended June 30, 2009.

PIONEER NATURAL RESOURCES COMPANY

In accordance with GAAP, the Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, deferred compensation plan assets, commodity derivative contracts and interest rate derivative contracts. See Note D of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding these assets and liabilities and the valuation techniques used to measure their fair values.

The Company’s commodity and interest rate derivative contracts that are periodically measured and recorded at fair value represent those derivatives that continue to be subject to market or credit risk. As of June 30, 2009, these contracts represented net liabilities of $51.8 million, including approximately $32.9 million of terminated hedge liabilities that are no longer subject to market risk. The ultimate liquidation value of the Company’s commodity and interest rate derivatives that are subject to market risk will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives’ fair values as of June 30, 2009. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information about the Company’s derivative instruments and market risk.

Capital resources. The Company’s primary capital resources are net cash provided by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally borrowings under the Company’s Credit Facility). Although the Company expects that these resources will be sufficient to fund its capital commitments during the foreseeable future, the recent turmoil in worldwide financial markets has resulted in the availability of external sources of short-term and long-term capital funding being less certain. For 2009, the Company currently expects that cash flow from operations and cash on hand will be sufficient to fund the Company’s capital budget.

Operating activities. Net cash provided by operating activities during the three and six month periods ended June 30, 2009 was $223.9 million and $248.3 million, respectively, as compared to $333.1 million and $510.7 million during the same respective periods of 2008. The decrease in net cash provided by operating activities for the three and six month periods ended June 30, 2009 is primarily due to decreased oil, NGL and gas prices from continuing operations, partially offset by an increase in commodity sales volumes.

Asset divestitures. In November 2007, the Company sold all of the common stock of its Canadian subsidiaries for net proceeds of $525.7 million, $132.8 million of which was deposited in a Canadian escrow account pending receipt from the Canada Revenue Agency of appropriate tax certifications. The tax certifications were received in January 2008 and the escrowed funds were subsequently released to the Company. Proceeds from disposition of assets of $145.8 million for the first half of 2008 are primarily comprised of the receipt of the escrowed Canadian sales proceeds, net of foreign exchange differentials.

The Company is evaluating a $100 million to $200 million potential sale of certain developed and undeveloped oil and gas properties to Pioneer Southwest. Any such transaction would be subject to negotiation of definitive agreements and the approvals of the boards of directors of the Company and Pioneer GP and the Conflicts Committee of the Pioneer GP board. There can be no assurance that the sale will be completed or as to its terms.

Financing activities. Net cash used in financing activities during the three months ended June 30, 2009 was $115.3 million while net cash provided by financing activities for the six month period ended June 30, 2009 was $27.5 million, as compared to $6.9 million and $11.9 million of net cash provided by financing activities during the same respective periods of 2008. During the three months ended June 30, 2009, the Company used excess cash provided by operating activities to reduce its borrowings under its Credit Facility.

As the Company pursues its strategy, it may utilize various financing sources, including, to the extent available, fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.

Liquidity. The Company’s principal sources of short-term liquidity are cash on hand and unused borrowing capacity under its Credit Facility. As of June 30, 2009, the Company had $982 million of outstanding borrowings under the Credit Facility. Including $46 million of undrawn and outstanding letters of credit under the Credit Facility, the Company had approximately $472 million of unused borrowing capacity as of June 30, 2009. If internal cash flows do not meet the Company’s expectations, the Company may further reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its Credit Facility, issuances of debt or equity securities or from other sources, such as asset sales. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal cash flows will be adequate to fund capital expenditures and dividend payments, and

PIONEER NATURAL RESOURCES COMPANY

that available borrowing capacity under the Company’s Credit Facility will provide adequate liquidity, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs. For instance, the amount that the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.

The Company’s Credit Facility is subject to certain covenants, including the maintenance of a PV Ratio. Effective April 29, 2009, the Company and its lenders amended the Credit Facility to provide the Company additional financial flexibility if longer-term commodity prices were to significantly deteriorate from current levels. The amendment reduced the required PV Ratio from 1.75 to 1.0 to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio reverts to 1.75 to 1.0, and provides that the Company may include in the PV Ratio calculation 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest.

Debt ratings. The Company receives debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s, which are subject to regular reviews. S&P’s rating for the Company is BB+ with a negative outlook. Moody’s rating for the Company is Ba1 with a negative outlook. The Company believes that S&P and Moody’s consider many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in the Company’s debt ratings could negatively impact the Company’s ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. As of June 30, 2009, the Company was in compliance with all of its debt covenants.

Book capitalization and current ratio. The Company’s net book capitalization at June 30, 2009 was $6.5 billion, consisting of $64 million of cash and cash equivalents, debt of $3.0 billion and stockholders’ equity of $3.5 billion. The Company’s net debt to net book capitalization was 46 percent and 44 percent at June 30, 2009 and December 31, 2008, respectively. The Company’s ratio of current assets to current liabilities was 0.83 to 1.00 at June 30, 2009 as compared to 0.70 to 1.00 at December 31, 2008.

New accounting pronouncements. In September 2006, the FASB issued SFAS 157. SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. During February 2008, the FASB issued FSP FAS 157-2. FSP FAS 157-2 delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2009, the Company adopted the remaining provisions of SFAS 157, for which delayed adoption was provided by FSP FAS 157-2. See Note D of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s adoption of FSP FAS 157-2.

In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer’s shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the recognition of capitalized research and development costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. The provisions of SFAS 141(R) also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. SFAS 141(R) is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. The Company became subject to the provisions of SFAS 141(R) on January 1, 2009.

In December 2007, the FASB issued SFAS 160. SFAS 160 amends ARB No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. The Company adopted the provisions of SFAS 160 on January 1, 2009.

PIONEER NATURAL RESOURCES COMPANY

In March 2008, the FASB issued SFAS 161. SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities by requiring entities to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 was adopted by the Company on January 1, 2009. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for disclosures about the Company’s derivative instruments and hedging activities.

In May 2008, the FASB issued FSP APB 14-1. FSP APB 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company adopted the provisions of FSP APB 14-1 on January 1, 2009. The adoption of FSP APB 14-1 increases the annual interest expense that the Company recognizes on its $480 million of 2.875% Senior Convertible Notes from an annual yield of 2.875 percent to 6.75 percent, the annual yield equivalent to a nonconvertible debt borrowing on the date of issuance. The adoption of FSP APB 14-1 also resulted in the reclassification of the estimated issuance date fair value of the 2.875% Senior Convertible Notes conversion privilege from long-term debt to shareholders’ equity in the accompanying consolidated balance sheets. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s adoption of FSP APB 14-1.

In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income (loss) allocation in computing basic and diluted net income (loss) per share under the two class method prescribed under SFAS 128, “Earnings per Share”. The Company adopted the provisions of FSP EITF 03-6-1 on January 1, 2009 and, in accordance with FSP EITF 03-6-1, applied its provisions retrospectively to prior-period net income per share computations. See Note K of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s basic and diluted net income (loss) computations for the three and six months ended June 30, 2009 and 2008.

In December 2008, the SEC released the Reserve Ruling. The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price. The Reserve Ruling becomes effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. During February 2009, the FASB announced a project to amend SFAS 19 to conform to the Reserve Ruling. The Company is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

In April 2009, the FASB issued FSP FAS 107-1, which amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments” and Accounting Principles Board Opinion No. 28, “Interim Financial Reporting.” FSP FAS 107-1 requires fair value disclosures by publicly traded companies of financial instruments for interim reporting purposes. FSP FAS 107-1 was adopted by the Company during the second quarter of 2009. See Note D of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for disclosures about the fair values of the Company’s financial instruments.

In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidelines for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have decreased and guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 was adopted by the Company during the second quarter of 2009.

In May 2009, the FASB issued SFAS 165, which provides additional guidelines in regards to subsequent event disclosures, including a new disclosure of the date through which the entity has evaluated subsequent events and the basis for that date. The Company adopted the provisions of SFAS 165 during the second quarter of 2009. See Note S of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for disclosures related to SFAS 165.

PIONEER NATURAL RESOURCES COMPANY

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. As such, the information contained herein should be read in conjunction with the related disclosures in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s potential exposure to market risks. The term “market risks”, insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices, foreign exchange rates and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. All of the Company’s market risk sensitive instruments are entered into for purposes other than speculative.

Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments, and from that date forward has accounted for derivative instruments using the mark-to-market accounting method. Therefore, the Company will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during the six months ending 2009:


	Derivative Contract Net Assets (Liabilities)
	Commodities (a)			Interest Rate (a)			Commodity Unwinds			Total
	(in thousands)

Fair value of contracts outstanding as of December 31, 2008	$	112,286		$	(9,903	)	$	(40,312	)	$	62,071
Changes in contract fair value (b)		(62,436	)		(4,415	)		—			(66,851	)
Contract maturities		(55,420	)		4,776			7,969			(42,675	)
Accretion of discount		—			—			(506	)		(506	)
Contract terminations		(3,877	)		—			—			(3,877	)

Fair value of contracts outstanding as of June 30, 2009	$	(9,447	)	$	(9,542	)	$	(32,849	)	$	(51,838	)

(a)	Represents the fair values of open derivative contracts subject to market risk.

(b)	At inception, derivative contracts entered into by the Company had no intrinsic value.

Interest rate sensitivity. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and Capital Commitments, Capital Resources and Liquidity included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information regarding debt transactions.

PIONEER NATURAL RESOURCES COMPANY

The following table provides information about financial instruments to which the Company was a party as of June 30, 2009 and that are sensitive to changes in interest rates. For debt obligations, the table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt’s estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of June 30, 2009. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on July 30, 2009.


	Six Months Ending December 31, 2009			Year Ending December 31,																	Liability Fair Value at June 30, 2009
	Six Months Ending December 31, 2009			2010			2011			2012			2013			Thereafter			Total		Liability Fair Value at June 30, 2009
	($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	—		$	6,110		$	480,000		$	1,639,985		$	2,126,095	$	1,794,074
Weighted average interest rate		5.74	%		5.74	%		5.74	%		5.73	%		5.74	%		6.83	%

Variable rate principal maturities	$	—		$	—		$	—		$	982,000		$	—		$	—		$	982,000	$	937,032
Weighted average interest rate		1.37	%		2.41	%		3.86	%		4.80	%
Interest Rate Swaps:
Credit Facility:
Notional debt amount (b)	$	400,000		$	227,222		$	25,000													$	9,542
Fixed rate payable (%)		2.87	%		2.97	%		3.00	%
Variable rate receivable (%)		0.62	%		1.66	%		3.11	%

(a)	Represents maturities of principal amounts excluding (i) debt issuance discounts and premiums and (ii) net deferred fair value hedge losses.

(b)	Represents weighted average notional contract amounts of interest rate derivatives.

Commodity price sensitivity. The following tables provide information about the Company’s oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2009. Although mitigated by the Company’s derivative activities, declines in commodity prices will reduce the Pioneer’s revenues and internal cash flows. Recent uncertainties in worldwide financial markets and recently proposed legislation restricting derivative activities may have the effect of reducing liquidity in the financial derivatives market, impeding the Company’s ability to enter into derivative contracts under acceptable terms.

Commodity derivative instruments. The Company manages commodity price risk with derivative contracts, such as swap and collar contracts. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum (“floor”) and maximum (“ceiling”) prices for the Company on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company’s realized price will exceed the variable market prices by the long put-to-short put price differential. With collar contracts, if the relevant market price is above the ceiling price, the Company pays the derivative counterparty the difference between the market price and the ceiling price; if the relevant market price is between the ceiling price and the floor price, the derivative has no cash settlement value; and, if the relevant market price is below the floor price, the Company receives the difference between the floor price and the market price from the counterparty. Collar contracts with short puts are similar to collar contracts, except that if the relevant market price is below the short put price, the Company receives the difference between the floor price and short put price from the counterparty.

See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for a description of the accounting procedures followed by the Company relative to its derivative financial instruments and for specific information regarding the terms of the Company’s derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

PIONEER NATURAL RESOURCES COMPANY


	Six Months Ending December 31, 2009			Year Ending December 31,												Asset (Liability) Fair Value at June 30, 2009
	Six Months Ending December 31, 2009			2010			2011			2012			2013			Asset (Liability) Fair Value at June 30, 2009
																(in thousands)
Oil Non-Hedge Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts		8,000			2,000			—			—			—		$	9,436
Weighted average fixed price per Bbl	$	67.02		$	98.32		$	—		$	—		$	—
Collar contracts		2,000			—			2,000			—			—		$	25,157
Weighted average ceiling price per Bbl	$	70.38		$	—		$	170.00		$	—		$	—
Weighted average floor price per Bbl	$	52.00		$	—		$	115.00		$	—		$	—
Collar contracts with short puts		17,500			24,000			19,000			—			—		$	(79,848	)
Weighted average ceiling price per Bbl	$	65.52		$	83.46		$	93.31		$	—		$	—
Weighted average floor price per Bbl	$	51.43		$	66.08		$	72.37		$	—		$	—
Weighted average short put price per Bbl	$	43.31		$	53.42		$	58.32		$	—		$	—
Average forward NYMEX oil prices (b)	$	70.51		$	76.33		$	79.36		$	—		$	—

NGL Non-Hedge Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts		3,750			1,250			—			—			—		$	5,466
Weighted average fixed price per Bbl	$	34.28		$	47.38		$	—		$	—		$	—
Average forward Mont Belvieu NGL prices (c)	$	32.91		$	34.84		$	—		$	—		$	—

Gas Non-Hedge Derivatives (a):
Average daily notional MMBtu volumes (b):
Swap contracts		135,000			125,000			—			—			—		$	69,209
Weighted average fixed price per MMBtu	$	6.21		$	6.60		$	—		$	—		$	—
Collar contracts		20,000			30,000			—			—			—		$	4,932
Weighted average ceiling price per MMBtu	$	5.90		$	7.52		$	—		$	—		$	—
Weighted average floor price per MMBtu	$	4.00		$	6.00		$	—		$	—		$	—
Collar contracts with short puts		150,000			95,000			50,000			—			—		$	2,878
Weighted average ceiling price per MMBtu	$	5.35		$	7.94		$	9.36		$	—		$	—
Weighted average floor price per MMBtu	$	4.18		$	6.00		$	7.00		$	—		$	—
Weighted average short put price per MMBtu	$	3.18		$	5.00		$	6.00		$	—		$	—
Basis swap contracts		285,000			205,000			60,000			20,000			10,000		$	(46,677	)
Weighted average fixed price per MMBtu	$	(0.96	)	$	(0.80	)	$	(0.82	)	$	(0.78	)	$	(0.71	)
Average forward NYMEX gas prices (b)	$	4.46		$	5.94		$	6.73		$	6.92		$	7.04

(a)

Subsequent to June 30, 2009, the Company entered into additional oil swap contracts for (i) 750 Bbls per day of the Company’s fourth quarter 2009 production at an average price of $69.35 per Bbl, (ii) 500 Bbls per day of the Company’s 2010 production at an average price of $73.45 per Bbl, (iii) 750 Bbls per day of the Company’s 2011 production at an average price of $77.25 per Bbl and (iv) 3,000 Bbls per day of the Company’s 2012 and 2013 production at an average price of $79.32 and $81.02, respectively. Additionally, the Company entered into oil collar contracts with short puts for (i) 1,000 Bbls per day of the Company’s 2010 production with a ceiling price of $87.75 per Bbl, a floor price of $70.00 Bbl and a short put price of $55.00 per Bbl, (ii) 6,000 Bbls per day of the Company’s 2011 production with a ceiling price of $98.70 per Bbl, a floor price of $74.17 per Bbl and a short put price of $59.17 per Bbl and (iii) 1,000 Bbls of the Company’s 2012 and 2013 production with a ceiling price of $103.50 per Bbl and $111.50 per Bbl, respectively, a floor price of $80.00 per Bbl and $83.00 per Bbl, respectively, and a short put price of $65.00 per Bbl and $68.00 per Bbl, respectively. Subsequent to June 30, 2009, the Company entered into additional NGL swap contracts for 750 Bbls per day of the Company’s 2011 and 2012 production at an average price of $34.65 per Bbl and $35.03 per Bbl, respectively. Subsequent to June 30, 2009, the Company entered into additional gas swap contracts for (i) 815 MMBtu per day and 2,500 MMBtu per day of the Company’s third and fourth quarter production, respectively, at an average price of $4.48 per MMBtu, (ii) 27,295 MMBtu per day of the Company’s 2010 production at an average price of $5.59 per MMBtu and (iii) 2,500 MMBtu per day of the Company’s 2011, 2012 and 2013 production at an average price of $6.65 per MMBtu, $6.77 per MMBtu and $6.89

PIONEER NATURAL RESOURCES COMPANY

per MMBtu, respectively. Subsequent to June 30, 2009, the Company also entered into additional gas basis swap contracts for (i) 10,000 MMBtu per day of the Company’s 2010 production at an average price differential of $0.26 per MMBtu and (ii) 40,000 per day of the Company’s 2011 production at an average price differential of $0.54 per MMBtu. Subsequent to June 30, 2009, the Company also entered into additional gas collar contracts with short puts for 50,000 MMBtu per day at a ceiling price of $8.55 per MMBtu, a floor price of $6.00 per MMBtu and a short put price of $4.50 per MMBtu.

(b)	The average forward NYMEX oil and gas prices are based on July 30, 2009 market quotes.

(c)	Forward Mont Belvieu NGL prices are not available as formal market quotes. These forward prices represent estimates as of July 30, 2009 provided by third parties who actively trade in the derivatives.

Item 4.

Controls and Procedures

Evaluation of disclosure controls and procedures. The Company’s management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (“the Exchange Act”), the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of the Company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the Company’s last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

The Company is party to the legal proceedings that are described under “Legal actions” in Note J of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The Company is also party to other proceedings and claims incidental to its business. While many of these other matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

Item 1A.

Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company’s Annual Report on Form 10-K under the headings “Item 1. Business – Competition, Markets and Regulations,” “Item 1A. Risk Factors” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect the Company’s business, financial condition or future results. Except as stated below and as set forth in Item 1A of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, there has been no material change in the Company’s risk factors from those described in the Annual Report on Form 10-K.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the Company’s financial condition and results of operations.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil, NGLs and gas the Company produces.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” (“ACESA”) or also known as the “Waxman-Markey cap-and-trade legislation”. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” such as carbon dioxide and methane, in the United States. ACESA would establish an economy-wide cap on emissions of greenhouse gases, or “GHGs,” in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and gas. The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.

It is not possible at this time to predict whether climate change legislation will be enacted, but any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require the Company to incur increased operating costs and could have an adverse effect on demand for the oil, NGLs and gas it produces.

PIONEER NATURAL RESOURCES COMPANY

The adoption of derivatives legislation by Congress could have an adverse impact on the Company’s ability to use derivative instruments to reduce the effect of commodity price risk associated with its business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives. The legislation would expand the power of the Commodity Futures Trading Commission, (“CFTC”) to regulate derivative transactions related to energy commodities, including oil, NGLs and gas, until the adoption of general legislation covering derivative regulatory reform. The CFTC recently conducted hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as oil, NGLs, gas and other energy products. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all over-the-counter (“OTC”) derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Although it is not possible at this time to predict whether or when the CFTC may adopt rules or Congress may act on derivatives legislation, any laws or regulations that may be adopted could have an adverse effect on the Company’s ability to utilize derivative instruments to reduce the effect of commodity price risk associated with its business.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase the Company’s costs of compliance and doing business.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company’s purchases of treasury stock during the three months ended June 30, 2009:


Period	Total Number of Shares (or Units) Purchased (a)	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs	Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs (b)

April 2009	8	$	20.55	—
June 2009	720	$	29.67	—

Total	728	$	29.57	—	$	355,789,018

(a)	Consists of shares withheld to satisfy tax withholding on employees’ share-based awards.

(b)	During 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock.

Item 4.

Submission of Matters to a Vote of Security Holders

The Company’s annual meeting of stockholders was held on June 17, 2009 in Irving, Texas. At the meeting, four proposals were submitted for a vote of stockholders (as described in the Company’s Proxy Statement dated May 7, 2009). The following is a brief description of each proposal and results of the stockholders’ votes.

PIONEER NATURAL RESOURCES COMPANY

Election of Directors. Prior to the meeting, the Board designated four nominees as Class III Directors with their terms to expire at the annual meeting in 2012 when their successors are elected and qualified. These nominees were Thomas D. Arthur, Andrew F. Cates, Scott J. Reiman and Scott D. Sheffield. Each nominee was elected as a director of the Company, with the results of the stockholder voting being as follows:


	For	Authority Withheld	Abstain	Broker Non-Votes

Thomas D. Arthur	100,979,492	2,016,277	—	—
Andrew F. Cates	100,750,414	2,245,355	—	—
Scott J. Reiman	100,831,874	2,163,895	—	—
Scott D. Sheffield	97,355,351	5,640,418	—	—

In addition, the term of office for the following directors continued after the annual meeting: Edison C. Buchanan, R. Hartwell Gardner, Andrew D. Lundquist, Charles E. Ramsey, Jr., Frank A. Risch and Jim A. Watson.

Ratification of selection of independent auditors. The engagement of Ernst & Young LLP as the Company’s independent auditors for 2009 was submitted to the stockholders for ratification. Such engagement was ratified, with the results of the stockholder voting being as follows:


For		100,042,544
Against		2,876,863
Abstain		76,362
Broker non-votes		—

Amendment to the 2006 Long-Term Incentive Plan. A proposal to amend the Company’s 2006 Long-Term Incentive Plan to increase the number of shares of common stock that the Company may issue thereunder by 4.5 million shares from 4.6 million to 9.1 million shares was submitted to the stockholders for approval. Such amendment was approved, with the results of the stockholder voting being as follows:


For		63,368,170
Against		27,786,121
Abstain		259,189
Broker non-votes		—

Amendment to the 2006 Long-Term Incentive Plan. To comply with the requirements of Section 162(m) of the Internal Revenue Code, a proposal to approve the eligible employees, business criteria and maximum annual per person compensation limits under the Company’s 2006 Long-Term Incentive Plan, including an amendment to increase the maximum number of shares of common stock that may be granted to an individual in any 12-month period from 250,000 shares to 400,000 shares, was submitted to the stockholders for approval. Such amendment was approved, with the results of the stockholder voting being as follows:


For		87,585,312
Against		3,641,956
Abstain		186,212
Broker non-votes		—

PIONEER NATURAL RESOURCES COMPANY

Item 6.

Exhibits

Exhibits


Exhibit Number		Description
10.1	—	Second Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009).

10.2	—	Third Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).

10.3	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).

10.4 (a)	—	Amendment No. 1 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009.

10.5 (a)	—	First Amendment to the Pioneer USA 401(k) and Matching Plan, effective January 1, 2009.

31.1 (a)	—	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2 (a)	—	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1 (b)	—	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2 (b)	—	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

(a)	Filed herewith.

(b)	Furnished herewith.

PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.


	PIONEER NATURAL RESOURCES COMPANY

Date: August 10, 2009	By:	/s/ Richard P. Dealy
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer

Date: August 10, 2009	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief Accounting Officer

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index


Exhibit Number		Description
10.1	—	Second Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009).

10.2	—	Third Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).

10.3	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long Term Incentive Plan effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).

10.4 (a)	—	Amendment No. 1 to the Company’s Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009.

10.5 (a)	—	First Amendment to the Pioneer USA 401(k) and Matching Plan, effective January 1, 2009.

31.1 (a)	—	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2 (a)	—	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1 (b)	—	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2 (b)	—	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

(a)	Filed herewith.

(b)	Furnished herewith.